Configuration for olefins and aromatics production

ABSTRACT

Processes herein may be used to thermally crack various hydrocarbon feeds, and may eliminate the refinery altogether while making the crude to chemicals process very flexible in terms of crude. In embodiments herein, crude is progressively separated into at least light and heavy fractions. Depending on the quality of the light and heavy fractions, these are routed to one of three upgrading operations, including a fixed bed hydroconversion unit, a fluidized catalytic conversion unit, or a residue hydrocracking unit that may utilize an ebullated bed reactor. Products from the upgrading operations may be used as feed to a steam cracker.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application, pursuant to 35 U.S.C. § 119(e), claims priority toU.S. Provisional Application Ser. Nos. 62/819,270, 62/819,282,62/819,247, 62/819,229, and 62/819,315, each filed Mar. 15, 2019, andeach of which is herein incorporated by reference in its entirety.

FIELD OF THE DISCLOSURE

Embodiments herein relate to processes and systems for producingpetrochemicals, such as olefins and aromatics, from crude oil and lowvalue heavy hydrocarbon streams.

BACKGROUND

High-boiling compounds in crude oil may cause significant operationalissues if they are sent to a steam cracker. High boiling compounds havea propensity to form coke, due in large part to their high asphaltenecontent. Therefore, the high boiling compounds are typically removedbefore sending the lighter fractions to different petrochemicals units,such as a steam cracker or an aromatic complex. The removal process,however, increases the capital cost of the overall process and lowersprofitability, as the removed high-boiling compounds can only be sold aslow-value fuel oil. In addition, conversion of vacuum residue withoutsignificant formation of HPNAs that are detrimental to steam crackerfurnaces downstream of the process has been a challenge to date.

U.S. Pat. No. 3,617,493 describes a process in which crude oil is sentto the convection section of a steam cracker and then to a separationzone, where the portion of the feed boiling below about 450° F. isseparated from the rest of the feed and then sent, with steam, into thehigh temperature portion of the steam cracker and subjected to crackingconditions.

U.S. Pat. No. 4,133,777 teaches a process in which feed oil initiallyflows downwardly in trickle flow through a fixed bed of HDM catalysts,and then passes downwardly through a fixed bed of promoted catalystscontaining selected GROUP VI and GROUP VIII metals, with very littlehydrocracking occurring in this combination process.

U.S. Pat. No. 5,603,824 disclosed a process of upgrading a waxyhydrocarbon feed mixture containing sulfur compounds which boils in thedistillate range, in order to reduce sulfur content and 85% point whilepreserving the high octane of naphtha by-products and maximizingdistillate yield. The process employs a single, downflow reactor havingat least two catalyst beds and an inter-bed redistributor between thebeds. The top bed contains a hydrocracking catalyst, preferably zeolitebeta, and the bottom bed contains a dewaxing catalyst, preferably ZSM-5.

U.S. Pat. No. 3,730,879 discloses a two-bed catalytic process for thehydrodesulfurization of crude oil or a reduced fraction, in which atleast 50 percent of the total pore volume of the first-bed catalyticconsists of pores in the 100-200 Angstrom diameter range.

U.S. Pat. No. 3,830,720 discloses a two-bed catalytic process forhydrocracking and hydrodesulfurizing residual oils, in which asmall-pore catalyst is disposed upstream of a large-pore catalyst.

U.S. Pat. No. 3,876,523 describes a novel catalyst and a process forcatalytically demetalizing and desulfurizing hydrocarbon oils comprisingresidual fractions. The process described therein utilizes a catalystcomprising a hydrogenation component, such as cobalt and molybdenumoxides, composited on an alumina. Although this catalyst is highlyeffective for demetalization of residual fractions and has goodstability with time on stream, its utility is remarkably improved whenthis catalyst is employed in a particular manner in combination with asecond catalyst having different critical characteristics. A catalyst ofthe type described in U.S. Pat. No. 3,876,523 will be referred as afirst catalyst, it being understood that this first catalyst is to besituated upstream of the second catalyst having differentcharacteristics.

U.S. Pat. No. 4,153,539 discloses that improved hydrogen utilizationand/or higher conversions of desired product is obtained inhydrotreating or hydrocracking processes when using amphora particlesfor hydrotreating of light hydrocarbon fractions, catalytic reforming,fixed-bed alkylation processes, and the like.

U.S. Pat. No. 4,016,067 discloses that hydrocarbon oils, preferablyresidual fractions, are catalytically hydroprocessed to very effectivelyremove both metals and sulfur and with particularly slow aging of thecatalyst system by contacting the oil sequentially with two catalysts ofdifferent characteristics. The first catalyst, located upstream of thesecond catalyst, is characterized by having at least 60% of its porevolume in pores greater than 100 A. in diameter and othercharacteristics hereinafter specified. The second catalyst, locateddownstream with respect to the first catalyst, is characterized byhaving a major fraction of its pore volume in pores less than 100 A. indiameter.

The dual catalyst apparatus of U.S. Pat. No. 4,016,067 is used todemetallize and/or desulfurize any hydrocarbon oil that has metalsand/or sulfur content-undesirably high for a particular application. Thedual catalyst apparatus is particularly effective for preparing lowmetals and/or low sulfur content feedstocks for catalytic cracking orfor coking. In the processing to remove metals and sulfur, andhydrocarbon oil also is concomitantly enriched in hydrogen, making it aneven more suitable chargestock for either of these processes.

U.S. Pat. No. 10,017,702 discloses a process for thermally crackingwhole crudes. The whole crude may be partially divided into multiplefractions and the separate fractions may be fed to a steam crackerthrough individual radiant coils.

US PG PUB 2019-0023999 A1 discloses separation of a crude into a lightcut and a heavy cut. The light cut is then fed to a steam cracker, andthe totality of the heavy cut is hydrotreated and/or hydrocracked.

In general, these and other prior processes for converting whole crudestypically convert less than 50 percent of the crude to the moredesirable end products, including petrochemicals such as ethylene,propylene, butenes, pentenes, and light aromatics, for example.Generally, 20 percent of the whole crude is removed up front inprocessing, removing the heaviest components that are hard to convert.About another 20 percent of the whole crude is typically converted topyrolysis oil, and about 10 percent is over-converted to methane.

SUMMARY

A process for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the process including:separating a whole crude into at least a light boiling fraction, amedium boiling fraction, and a high boiling residue fraction;hydrocracking the high boiling residue fraction to form a hydrocrackedeffluent, and separating the hydrocracked effluent to produce a residhydrocracked fraction and a fuel oil fraction; destructivelyhydrogenating the medium boiling fraction to form a first destructivelyhydrogenated effluent; destructively hydrogenating the residhydrocracked fraction to produce a second destructively hydrogenatedeffluent; mixing the first and second destructively hydrogenatedeffluents to form a mixture and hydrocracking the mixture to formproduce a hydrotreated and hydrocracked effluent; and feeding thehydrotreated and hydrocracked effluent and the light boiling fraction toat least one of a steam cracker and an aromatics complex to converthydrocarbons therein into petrochemicals and a pyrolysis oil and/or anultra-low sulfur fuel oil (ULSFO).

A system for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the system including: aseparation system for separating a whole crude into at least a lightboiling fraction, a medium boiling fraction, and a high boiling residuefraction; a hydrocracker for hydrocracking the high boiling residuefraction to form a hydrocracked effluent, and separating thehydrocracked effluent to produce a resid hydrocracked fraction and afuel oil fraction; a first conditioning reactor for destructivelyhydrogenating the medium boiling fraction to form a first destructivelyhydrogenated effluent; a second conditioning reactor for destructivelyhydrogenating the resid hydrocracked fraction to produce a seconddestructively hydrogenated effluent; a mixer for mixing the first andsecond destructively hydrogenated effluents to form a mixture and ahydrocracker for hydrocracking the mixture to form produce ahydrotreated and hydrocracked effluent; one or more flow lines forfeeding the hydrotreated and hydrocracked effluent and the light boilingfraction to at least one of a steam cracker and an aromatics complex toconvert hydrocarbons therein into petrochemicals and a pyrolysis oiland/or an ultra-low sulfur fuel oil (ULSFO).

Other aspects and advantages will be apparent from the followingdescription and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 2 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 3 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 4 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 5 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 6 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

FIG. 7 is a simplified process flow diagram of a system for convertingwhole crudes and heavy hydrocarbons according to embodiments herein.

DETAILED DESCRIPTION

As used herein, the term “petrochemicals” refers to hydrocarbonsincluding light olefins and diolefins and C6-C8 aromatics.Petrochemicals thus refers to hydrocarbons including ethylene,propylene, butenes, butadienes, pentenes, pentadienes, as well asbenzene, toluene, and xylenes. Referring to a subset of petrochemicals,the term “chemicals,” as used herein, refers to ethylene, propylene,butadiene, 1-butene, isobutylene, benzene, toluene, and para-xylenes.

Hydrotreating is a catalytic process, usually carried out in thepresence of free hydrogen, in which the primary purpose when used toprocess hydrocarbon feedstocks is the removal of various metalcontaminants (e.g., arsenic), heteroatoms (e.g., sulfur, nitrogen andoxygen), and aromatics from the feedstock. Generally, in hydrotreatingoperations cracking of the hydrocarbon molecules (i.e., breaking thelarger hydrocarbon molecules into smaller hydrocarbon molecules) isminimized. As used herein, the term “hydrotreating” refers to a refiningprocess whereby a feed stream is reacted with hydrogen gas in thepresence of a catalyst to remove impurities such as sulfur, nitrogen,oxygen, and/or metals (e.g. nickel, or vanadium) from the feed stream(e.g. the atmospheric tower bottoms) through reductive processes.Hydrotreating processes may vary substantially depending on the type offeed to a hydrotreater. For example, light feeds (e.g. naphtha) containvery little and few types of impurities, whereas heavy feeds (e.g. ATBs)typically possess many different heavy compounds present in a crude oil.Apart from having heavy compounds, impurities in heavy feeds are morecomplex and difficult to treat than those present in light feeds.Therefore, hydrotreating of light feeds is generally performed at lowerreaction severity, whereas heavy feeds require higher reaction pressuresand temperatures.

Hydrocracking refers to a process in which hydrogenation anddehydrogenation accompanies the cracking/fragmentation of hydrocarbons,e.g., converting heavier hydrocarbons into lighter hydrocarbons, orconverting aromatics and/or cycloparaffins(naphthenes) into non-cyclicbranched paraffins.

“Conditioning” and like terms as used herein refers to conversion ofhydrocarbons by one or both of hydrocracking and hydrotreating.“Destructive hydrogenation” and like terms refers to cracking of thehydrocarbon molecular bonds of a hydrocarbon, and the associatedhydrogen saturation of the remaining hydrocarbon fragments, which cancreate stable lower boiling point hydrocarbon oil products, and may beinclusive of both hydrocracking and hydrotreating.

“API gravity” refers to the gravity of a petroleum feedstock or productrelative to water, as determined by ASTM D4052-11.

Embodiments herein relate to processes and systems that take crude oiland/or low value heavy hydrocarbons as feed and produces petrochemicals,such as light olefins (ethylene, propylene, and/or butenes) andaromatics. More specifically, embodiments herein are directed towardmethods and systems for making olefins and aromatics by thermal crackingof a pre-conditioned crude oil or condensate. Processes herein maycondition the residuum fraction of whole crude oils and naturalcondensates to produce feedstocks useful as a steam cracker feedstock.

The integration of conditioning, fractionation, and steam cracking mayresult in a highly efficient facility, and in some embodiments mayconvert greater than 55%, greater than 60%, greater than 65%, greaterthan 70%, greater than 75%, greater than 80%, or greater than 85% of thewhole crude to petrochemicals. In other embodiments, the integration ofconditioning, fractionation, and steam cracking may result in a highlyefficient facility, and in some embodiments may convert greater than55%, greater than 60%, greater than 65%, greater than 70%, greater than75%, greater than 80% or greater than 85% of the whole crude tochemicals. Embodiments herein may thus provide systems and processes forconditioning feeds including even the heaviest, most undesirableresiduum components into components that can be vaporized and passedinto the radiant section of a steam cracker, substantially improvingover the low petrochemical conversion of prior processes.

Hydrocarbon mixtures useful in embodiments disclosed herein may includevarious hydrocarbon mixtures having a boiling range, where the endboiling point of the mixture may be greater than 500° C., such asgreater than 525° C., 550° C., or 575° C. The amount of high boilinghydrocarbons, such as hydrocarbons boiling over 550° C., may be aslittle as 0.1 wt %, 1 wt % or 2 wt %, but can be as high as 10 wt %, 25wt %, 50 wt % or greater. The description is explained with respect tocrude oil, such as whole crude oil, but any high boiling end pointhydrocarbon mixture can be used. However, processes disclosed herein canbe applied to crudes, condensates and hydrocarbons with a wide boilingcurve and end points higher than 500° C. Such hydrocarbon mixtures mayinclude whole crudes, virgin crudes, hydroprocessed crudes, gas oils,vacuum gas oils, heating oils, jet fuels, diesels, kerosenes, gasolines,synthetic naphthas, raffinate reformates, Fischer-Tropsch liquids,Fischer-Tropsch gases, natural gasolines, distillates, virgin naphthas,natural gas condensates, atmospheric pipestill bottoms, vacuum pipestillstreams including bottoms, wide boiling range naphtha to gas oilcondensates, heavy non-virgin hydrocarbon streams from refineries,vacuum gas oils, heavy gas oils, atmospheric residuum, hydrocracker wax,and Fischer-Tropsch wax, among others. In some embodiments, thehydrocarbon mixture may include hydrocarbons boiling from the naphtharange or lighter to the vacuum gas oil range or heavier.

When the end boiling point of the hydrocarbon mixture may be high, suchas over 550° C. in some embodiments, the hydrocarbon mixture cannot beprocessed directly in a steam pyrolysis reactor to produce olefins. Thepresence of these heavy hydrocarbons results in the formation of coke inthe reactor, where the coking may occur in one or more of the convectionzone preheating coils or superheating coils, in the radiant coils, or intransfer line exchangers, and such coking may occur rapidly, such as infew hours. Whole crude is not typically cracked commercially, as it isnot economical. It is generally fractionated, and only specific cuts areused in a steam pyrolysis heater to produce olefins. The remainder isused in other processes. The cracking reaction proceeds via a freeradical mechanism. Hence, high ethylene yield can be achieved when it iscracked at high temperatures. Lighter feeds, like butanes and pentanes,require a high reactor temperature to obtain high olefin yields. Heavyfeeds, like gas oil and vacuum gas oil (VGO), require lowertemperatures. Crude contains a distribution of compounds from butanes toVGO and residue (material boiling over 550° C.). Subjecting the wholecrude without separation at high temperatures produces a high yield ofcoke (byproduct of cracking hydrocarbons at high severity) and plugs thereactor. The steam pyrolysis reactor has to be periodically shut downand the coke is cleaned by steam/air decoking. The time between twocleaning periods when the olefins are produced is called run length.When whole crude is cracked without separation, coke can deposit in theconvection section coils (vaporizing the fluid), in the radiant section(where the olefin producing reactions occur) and/or in the transfer lineexchanger (where the reactions are stopped quickly by cooling topreserve the olefin yields).

Processes and systems according to embodiments herein may include a feedpreparation section, a crude conditioning section, an aromatic complex,and a steam cracker. The feed preparation section may include adesalter, for example.

The desalted crude is then conditioned and processed such that crackablefeed is being sent to a steam cracker and/or an aromatic complex. Theconditioning section may allow an operator to maximize thepetrochemicals yield while maintaining a reasonable decoking frequencyof the furnaces. Another objective of the crude conditioning unit is toensure complete or essentially complete (95%+) conversion of asphaltenesto lower boiling point components that enhance the petrochemicals yieldwhile reducing the formation of heavy polynuclear aromatics (HPNAs).

Processes according to embodiments herein may thus convert heavierfractions of crude oil into high-value petrochemicals and may minimizethe amount of hydrocarbons sent to a fuel oil pool, which substantiallyincreases profitability. The small fuel oil pool that is produced mayalso be upgraded into a low-sulfur, IMO 2020 compliant fuel oil, furtherincreasing the value of the products.

As noted above, high-boiling compounds in the crude oil may causesignificant operational issues if they are sent to a steam cracker, dueto their propensity to form coke, mainly because of their highasphaltene content. Therefore, the high boiling compounds are typicallyremoved before sending the lighter fractions to different petrochemicalsunits, such as a steam cracker and aromatic complex. The removal processincreases the capital cost of the overall process and lowersprofitability, as the removed high-boiling compounds can only be sold aslow-value fuel oil. In addition, conversion of vacuum residue withoutsignificant formation of HPNAs that are detrimental to steam crackerfurnaces downstream of the process has been a challenge to date in theindustry. Processes and systems according to embodiments herein mayovercome these challenges.

The configurations of systems and processes for the conversion of wholecrudes and heavy hydrocarbons according to embodiments described hereinmay efficiently handle resid conversion while maximizing thepetrochemicals conversion and maintaining lower coking propensity in thesteam cracker. This is achieved by integrating a resid hydrocrackingreactor to the crude conditioning process, enabling conversion of highboiling compounds to lighter components. Resid hydrocracking unitsaccording to embodiments herein may include fixed bed residhydrocracking units, ebullated bed resid hydrocracking reactors, as wellas slurry bed resid hydrocracking reactors, in various embodiments.

The upgraded crude streams from the crude conditioning unit, such asfrom a fixed bed crude conditioning unit and a hydrocracker, aresuitable feedstocks for the steam cracker as well as an aromaticcomplex. Such may lead to decreasing the overall process yields of lowvalue fuel oil and increasing the yields of high value olefins andaromatics, such as benzene, toluene, and xylenes (BTX).

Separation of various fractions, such as a low boiling hydrocarbonfraction (a 160° C.− fraction, for example), a middle boiling fraction(a 160-490° C. fraction, for example), and a high boiling fraction (a490° C.+ fraction, for example) may enhance the capital efficiently andoperating costs of the processes and systems disclosed herein. Whilereferring to three cuts in many embodiments herein, it is recognized bythe present inventors that condensates, typically having a small amountof high boiling components, and whole crudes, having a greater quantityof high boiling components, may be processed differently. Accordingly,one, two, three or more individual cuts can be performed for the wideboiling range petroleum feeds, and each cut can be processed separatelyat optimum conditions.

Separation of the whole crude into the desired fractions may beperformed using one or more separators (distillation columns, flashdrums, etc.). In some embodiments, separation of the petroleum feeds maybe performed in an integrated separation device (ISD), such as disclosedin US20130197283, which is incorporated herein by reference. In the ISD,an initial separation of a low boiling fraction is performed in the ISDbased on a combination of centrifugal and cyclonic effects to separatethe desired vapor fraction from liquid. An additional separation stepmay then be used to separate a middle boiling fraction from high boilingcomponents.

Typically, hydrocarbon components boiling above 490° C. containasphaltenes and Conradson Carbon Residue, and thus need to be processedappropriately, as described further below. While embodiments aredescribed as including a fraction below about 90° C.-250° C., such as a160° C.− fraction and a fraction above about 400° C.-560° C., such as a490° C.+ fraction, it is noted that the actual cut points may be variedbased on the type of whole crude or other heavy fractions beingprocessed. For example, for a crude containing a low metals or nitrogencontent, or a large quantity of “easier-to-process” components boiling,for instance, at temperatures up to 525° C., 540° C., or 565° C., it maybe possible to increase the mid/high cut point while still achieving thebenefits of embodiments herein. Similarly, the low/mid cut point may beas high as 220° C. in some embodiments, or as high as 250° C. in otherembodiments. Further, it has been found that a low/mid cut point ofabout 160° C. may provide a benefit for sizing and operation of thereactors, such as a fixed bed conditioning reactor, for conditioning themid fraction hydrocarbons (middle cut). Further still, for some feeds,such as condensate, the low/mid cut point may be as high as 565° C. Theability to vary the cut points may add flexibility to process schemesaccording to embodiments herein, allowing for processing of a widevariety of feeds while still producing the product mixture desired.

Accordingly, in some embodiments, the light cut may include hydrocarbonshaving a boiling point up to about 90° C. (e.g., a 90° C.− fraction), upto about 100° C., up to about 110° C., up to about 120° C., up to about130° C., up to about 140° C., up to about 150° C., up to about 160° C.,up to about 170° C., up to about 180° C., up to about 190° C., up toabout 200° C., up to about 210° C., up to about 220° C., up to about230° C., up to about 240° C., up to about 250° C. (e.g., a 250° C.−fraction), up to about 300° C., up to about 350° C., up to about 400°C., up to about 500° C., or up to about 565° C. Embodiments herein alsocontemplate the light cut being hydrocarbons having boiling points up totemperatures intermediate the aforementioned ranges.

Depending upon the fractionation mechanism used, the light hydrocarbon“cut” may be relatively clean, meaning the light fraction may not haveany substantial amount (>1 wt % as used herein) of compounds boilingabove the intended boiling temperature target. For example, a 160° C.−cut may not have any substantial amount of hydrocarbon compounds boilingabove 160° C. (i.e., >1 wt %). In other embodiments, the intended target“cut” temperatures noted above may be a 95% boiling point temperature,or in other embodiments as an 85% boiling point temperature, such as maybe measured using ASTM D86 or ASTM D2887, or a True Boiling Point (TBP)analysis according to ASTM D2892, for example, and ASTM D7169 for heavystreams, such as those boiling above about 400° C. In such embodiments,there may be up to 5 wt % or up to 15 wt % of compounds above theindicated “cut” point temperature. For many whole crudes, the low/midcut point may be such that the light boiling fraction has a 95% boilingpoint temperature in the range from about 90° C. to about 250° C. Forother feeds, however, such as condensate, the light boiling fraction mayhave a 95% boiling point temperature in the range from about 500° C. toabout 565° C., for example.

In some embodiments, the middle cut may include hydrocarbons having aboiling point from a lower limit of the light cut upper temperature(e.g., 90° C., 100° C., 110° C., 120° C., 130° C., 140° C., 150° C.,160° C., 170° C., 180° C., 190° C., 200° C., 210° C., 220° C., 230° C.,240° C., 250° C., 300° C., 350° C., or 400° C., for example) to an upperlimit of hydrocarbons having a boiling point up to about 350° C., up toabout 375° C., up to about 400° C., up to about 410° C., up to about420° C., up to about 430° C., up to about 440° C., up to about 450° C.,up to about 460° C., up to about 480° C., up to about 490° C., up toabout 500° C., up to about 520° C., up to about 540° C., up to about560° C., or up to about 580° C. As used herein, for example, a middlecut having a lower limit of 160° C. and an upper limit of 490° C. may bereferred to as a 160° C. to 490° C. cut or fraction. Embodiments hereinalso contemplate the middle cut being hydrocarbons having boiling pointsfrom and/or up to temperatures intermediate the aforementioned ranges.

Depending upon the fractionation mechanism, the hydrocarbon “cut” forthe middle cut may be relatively clean, meaning the middle cut may nothave any substantial amount (>1 wt %) of compounds boiling below and/ormay not have any substantial amount (>1 wt %) of compounds boiling abovethe intended boiling temperature target limits. For example, a 160° C.to 490° C. cut may not have any substantial amount of hydrocarboncompounds boiling below 160° C. or above 490° C. In other embodiments,the intended target “cut” temperatures noted above may be a 5 wt % or 15wt % boiling point temperature on the lower limit and/or a 95% or 85%boiling point temperature on the upper limit, such as may be measuredusing ASTM D86 or ASTM D2887, or a True Boiling Point (TBP) analysisaccording to ASTM D2892, for example, and ASTM D7169 for heavy streams,such as those boiling above about 400° C. In such embodiments, there maybe up to 5 wt % or up to 15 wt % of compounds above and/or below the“cut” point temperature, respectively.

In some embodiments, the heavy cut may include hydrocarbons having aboiling point above about 350° C., above about 375° C., above about 400°C. (e.g., a 400° C.+ fraction), above about 420° C., above about 440°C., above about 460° C., above about 480° C., above about 490° C., aboveabout 500° C., above about 510° C., above about 520° C., above about530° C., above about 540° C., above about 560° C., above about 580° C.,above about 590° C., above about 600° C. (e.g., a 600° C.+ fraction), orabove about 700° C. Embodiments herein also contemplate the heavy cutbeing hydrocarbons having boiling points above temperatures intermediatethe aforementioned temperatures.

Depending upon the fractionation mechanism, the heavy hydrocarbon “cut”may be relatively clean, meaning the heavy fraction may not have anysubstantial amount (>1 wt %) of compounds boiling below the intendedboiling temperature target. For example, a 490° C.+ cut may not have anysubstantial amount of hydrocarbon compounds boiling below 490° C. Inother embodiments, the intended target “cut” temperatures noted abovemay be a 95% boiling point temperature, or in other embodiments as an85% boiling point temperature, such as may be measured using ASTM D86 orASTM D2887, or a True Boiling Point (TBP) analysis according to ASTMD2892, for example, and ASTM D7169 for heavy streams, such as thoseboiling above about 400° C. In such embodiments, there may be up to 5 wt% or up to 15 wt % of compounds, respectively, below the “cut” pointtemperature.

While examples below are given with respect to limited temperatureranges, it is envisioned that any of the temperature ranges prescribedabove can be used in the processes described herein. Further, withrespect to cut points, those referred to in the examples below may beclean, as described above, or may refer to 5% or 15% boilingtemperatures for lower limits, or may refer to 85% or 95% boilingtemperatures for upper limits.

Following fractionation, the light cut, such as a 160° C.− cut, may befed to a steam cracker section of the system with or without furtherprocessing. The light cut fed to the steam cracker section may includelight naphtha and lighter hydrocarbons, for example, and in someembodiments may include heavy naphtha boiling range hydrocarbons.

The mid-range hydrocarbon cut may be conditioned using one or more fixedbed reactors, such as hydrotreating and/or hydrocracking reactors, eachof which may destructively hydrogenate the hydrocarbons in the mid-cut.The conditioning reactors may include catalysts for metals removal,sulfur removal, nitrogen removal, and the conditioning in these reactorsmay overall add hydrogen to the hydrocarbon components, making themeasier to process downstream to produce petrochemicals. The fixed bedcatalyst systems in the mid-cut conditioning zone, for example, maycontain different layers of demetalizing, destructive hydrogenation andmesoporous zeolite hydrocracking catalysts to optimize the conversion ofthe heavy materials to a balance between a highly paraffinic stream thatis suitable for olefins production and a rich in aromatics stream thatis suitable for aromatics production.

In some embodiments, it may be desirable to further separate the mid-cutinto a low-mid cut and a high-mid cut. For example, a mid-cut having aboiling range from 160° C. to 490° C. may be divided into a low-mid cuthaving a boiling range from about 160° C. to about 325° C. and ahigh-mid cut having a boiling range from about 325° C. to about 490° C.The conditioning trains may thus be configured to more selectivelyconvert the hydrocarbon components in the respective low and high midcuts to the desired conditioned effluents, where each train may beconfigured based on preferred catalysts to destructively hydrogenate thehydrocarbons therein, reactor sizing for expected feed volumes andcatalyst lifetime, as well as operating conditions to achieve thedesired conversions to naphtha range containing steam crackerfeedstocks. Similarly, division of the mid cut into three or moresub-cuts is also contemplated.

The hydrocarbons in the heavy cut may also be conditioned using one ormore fixed bed reactors, slurry reactors, or ebullated bed reactors.Conditioning of the heavy cut, such as 490° C.+ hydrocarbons, may beperformed, for example, in a residue hydrocracker, and may enhance theconversion of low value streams to high value petrochemical products viasteam cracking. Residue hydrocracking may be performed, for example, ina fixed bed residue hydrocracker, an ebullated bed reactor, such as anLC-FINING or LC-MAX reactor system, as well as slurry reactors, such asLC-SLURRY reactors, each available from Chevron Lummus Global. It isrecognized, however, that the lifetime of destructive hydrogenationand/or hydrocracking catalysts may be negatively impacted by heaviercomponents, such as where the feed includes components boiling above565° C., for example. Similar to the mid-cut, division of the heavy cutinto one or more sub-cuts is also contemplated.

The crude conditioning section, inclusive of the mid- and heavy-cutconditioning, is designed to achieve four (4) goals. First, the crudeconditioning section may be used to increase the concentration ofparaffins and naphthenes in the crude. Second, the conditioning sectionmay decrease the concentration of polynuclear aromatic hydrocarbons(PNAs) in the crude. Third, the conditioning section may reduce thefinal boiling point (FBP) of the crude to below 540° C. And, fourth, theconditioning section may minimize the vacuum residue fraction of thecrude oil.

Embodiments herein, when conditioning the middle and heavy fractions,may target conversion of the heavier hydrocarbons to form hydrocarbonslighter than diesel, for example. The destructive hydrogenationcatalysts and operating conditions may thus be selected to target theconversion of the hydrocarbons, or the hydrocarbons in the respectivefractions, to primarily (>50 wt %) naphtha range hydrocarbons, such asgreater than 60 wt % naphtha range hydrocarbons, or such as greater than70 wt % naphtha range hydrocarbons. The use of catalysts and operatingconditions in the conditioning sections to target lighter hydrocarbonproducts may enhance the operability of the steam cracker and theproduction of petrochemicals.

In some embodiments, conditioning of the heavy cut, such as a 490° C.+cut, may result in conversion of at least 70 wt % of the compoundsboiling in excess of 565° C. to lighter boiling compounds. Otherembodiments may result in conversion of greater than 75 wt %, greaterthan 80 wt %, or greater than 85 wt % of the compounds boiling in excessof 565° C. to lighter boiling compounds.

In some embodiments, conditioning of the middle cut, such as a 160° C.to 490° C. cut, may result in conversion of greater than 50 wt % of thehydrocarbons therein to naphtha range hydrocarbons. In otherembodiments, conditioning of the middle cut may result in conversion ofgreater than 55 wt %, greater than 60 wt %, or greater than 65 wt %, orgreater than 70 wt % of the hydrocarbons therein to naphtha rangehydrocarbons.

In some embodiments, collective conditioning of the middle cut and theheavy cut may result in an overall conversion of greater than 50 wt % ofthe hydrocarbons therein to naphtha range hydrocarbons. In otherembodiments, conditioning of the middle cut and the heavy cut may resultin conversion of greater than 55 wt %, greater than 60 wt %, or greaterthan 65 wt % of the hydrocarbons therein to naphtha range hydrocarbons.

As a result of such initial separations and conditioning, feeds to thesteam cracker may be fed, in some embodiments, directly to the steamcracker without further processing. The light cut, having preferredproperties, including one or more of boiling point, API, BMCI, hydrogencontent, nitrogen content, sulfur content, viscosity, MCRT, or totalmetals content, may be fed directly to the steam cracker followingseparations in some embodiments. Effluents from the middle cutconditioning may also be fed directly to the steam cracker according toembodiments herein. Likewise, effluents from the heavy cut conditioningmay be fed directly to the steam cracker in some embodiments.

The conditioning of the respective fractions as described herein mayallow for the steam cracker, even while processing multiple feeds ofvarying boiling point ranges, to run for an extended period of time. Insome embodiments, the steam cracker may be able to run for anuninterrupted run length of at least three years; at least four years inother embodiments; and at least five years in yet other embodiments.

Further, the initial hydrocarbon cut points, reactor sizes, catalysts,etc. may be adjusted or configured such that a run time of the steamcracker operations and conditioning processes may be aligned. Thecatalysts, reactor sizes, and conditions may be configured such that arun time of the conditioning unit is aligned with the run time of thesteam cracker. Catalyst volumes, catalyst types, and reaction severitymay all play a role in determining conditioning unit run times. Further,the extent of conditioning of the heavier hydrocarbons in the crude mayimpact coking in the thermal steam cracker. To maximize plant uptime,embodiments herein contemplate design and configuration of the overallsystem such that the conditioning system has a similar anticipated runtime as the steam cracker for a given feedstock or a variety ofanticipated feedstocks. Further, embodiments herein contemplateadjustment of reaction conditions (cut point, T, P, space velocity,etc.) in the conditioning section and/or the steam cracker based on afeedstock being processed, such that a run time of the conditioningsection and the steam cracker are similar or aligned.

Alignment of run times may result in minimal downtime, such as where acatalyst turnover in a conditioning reactor is conducted concurrentlywith decoking of the steam cracker. Where the conditioning systemsinclude multiple reactors or types of reactors, alignment of the runtimes may be based on the expected steam cracker performance. Further,where a hydrotreater, for example, may have a significantly longer runtime than a hydrocracker in the conditioning section, parallel reactortrains and/or bypass processing may be used such that the overall runtimes of the conditioning and steam cracking units may be aligned.

Bypass processing may include, for example, temporarily processing aheavy (e.g., 490° C.+) cut in a reactor that normally processes alighter feedstock, such as a mid-cut or a heavy mid-cut fraction. Theheavier feedstock is anticipated to have more severe conditions andshorter catalyst life, and thus temporarily processing the heavies in amid-range hydrocarbons conditioning reactor during a heavies catalystchange may allow the whole crude feed to continue to be fed to the steamcracker, without a shutdown, while the heavies conditioning reactorcatalyst is replaced. Configuration of the mid-range conditioningreactors may also take into account the anticipated bypass processingwhen designing the overall system for aligned run times.

Recognizing that fixed bed conditioning may be detrimental to the lightends of some feedstocks, it may be desirable to perform an initialseparation, such that the heavier components are conditioned for steamcracker feed while the lighter components, already suitable for steamcracker feed, are not further conditioned. Referring now to FIG. 1, asimplified process flow diagram of a system for converting whole crudesand heavy hydrocarbons according to embodiments herein is illustrated.

A wide boiling range hydrocarbon feed, such as a desalted crude 1, maybe fed to a separation system 3. Separation system 3 may be anintegrated separation device (ISD), as described above, and includingseparation and heat integration, for example. In separation system 3,the desalted crude 1 may be separated into three fractions, including(a) a light cut, such as a 160° C.− fraction 5 that doesn't require anyconditioning and can be used as feed to the steam cracker section 7; (b)a middle cut, such as a 160-490° C. fraction 9 that may be upgraded in aconditioning section 11 to produce lighter hydrocarbons, such as ahighly paraffinic stream 13 suitable for processing in the steamcracking section 7; and, (c) a heavy cut, such as a 490° C.+ fraction15, which contains the most refractory materials in the crude, and whichcan be upgraded in a residue hydrocracker 17. Other cut points may alsobe used to route the desired fractions and hydrocarbons therein todesired units for conditioning and/or steam cracking. The residuehydrocracker may produce an ultra-low sulfur fuel oil 19 and a stream 21that is suitable to be fed to the conditioning system for furtherconditioning and to produce additional hydrocarbons suitable forconversion to petrochemicals in the steam cracker section 7. Theprocessing of the feeds in the steam cracker section may produce one ormore petrochemical streams 23, such as ethylene, propylene, and butene,among others, as well as a higher boiling pyrolysis oil fraction 25.

In some embodiments, the mid cut fraction, such as 160-490° C. stream,may be processed initially in a fixed bed destructive hydrogenationreactor 27. The 490° C.+ stream may be processed in residuehydrocracking reactor system 17, which may include one or more reactors,such as utilizing an ebullated bed extrudate catalyst or slurrycatalyst, which converts some of the hydrocarbons into lighterhydrocarbons, such as 490° C.− hydrocarbons. The additional lighterhydrocarbons may be treated in a fixed bed destructive hydrogenationreactor, which may be the same reactor used to condition the mid cut,or, as illustrated, a separate fixed bed destructive hydrogenationreactor 29 that may contain a catalyst tailored to effectively conditionthe once-converted hydrocarbons received from the residue hydrocracking.The reaction products 31, 33 from the hydrotreated middle cut (e.g., a160-490° C. stream 9) and the hydrotreated lighter material (e.g., 490°C.− resid hydrocracker effluent), respectively from the fixed beddestructive hydrogenation reactors 27, 29, may then be combined andco-processed in a fixed bed hydrocracking reactor 35, producing afeedstock 13 suitable for processing in steam cracker section 17 forconversion into light olefins and other valuable petrochemicals. Theunconverted portion of the resid hydrocracking reactor effluent may beprocessed, for example, in a fixed bed hydrodesulfurization unit (notillustrated) to produce ultra-low sulfur fuel oil (ULSFO).

In some embodiments, conditioning reactors 27 and 29 may includedestructive hydrogenation catalysts (first stage conditioning), whileconditioning reactors 35 include hydrocracking catalysts (second stageconditioning). Further, the first stage conditioning may, in someembodiments, include catalysts to target lowering a content ofpolynuclear aromatic compounds, thereby conditioning the feed to be moreeasily processed in the steam cracker.

Referring now to FIG. 2, a simplified process flow diagram of a systemfor converting whole crudes and heavy hydrocarbons according toembodiments herein is illustrated, where like numerals represent likeparts. In this embodiment, the desalted whole crude is processed similarto that as described above for FIG. 1. In this embodiment, the heavycut, such as a 490° C.+ stream 15 and the pyrolysis oil stream 25 arecombined and processed in the residue hydrocracking reactor(s) toconvert some of the hydrocarbons in the streams into 490° C.−hydrocarbons, which is further processed in fixed bed destructivehydrogenation reactor 29.

As described above, the destructive hydrogenation reactors 27, 29 may beused to condition the middle cut, such as a 160-490° C. stream 9, andthe effluent (such as a 490° C.−) stream 21 from the resid hydrocrackingsystem 17. In some embodiments, the streams may be processed in the samedestructive hydrogenation reactor. However, it has been found that, dueto the nature of the feed compounds for various crudes, processing in asingle reaction train may result in a stream with molecules that containmore aromatic rings than the molecules in straight run Arab Light orArab extra light crudes in the same boiling range. As a result, moresevere conditions may be necessary to sufficiently saturate themolecules, which has a negative impact on destructive hydrogenationcatalyst life and/or capital investment. If the previously convertedmaterials in stream 21 are co-processed with the straight run middle cutmaterial in stream 9, the turnaround time for a single destructivehydrogenation train may drop below that of the steam cracking section,and/or a spare destructive hydrogenation train would be required toprovide a steady stream of feed to the steam cracking section while thedestructive hydrogenation catalyst system is undergoing regenerationand/or replacement. The aforementioned would also be applicable to othertypes of crude, such as desalted oils, condensate, biogenic oil,synthesis crude, tight oil, heavy hydrocarbons, reconstituted crudes,and bitumen derived oils.

To alleviate the issues of catalyst life/turnaround time, the fixed beddestructive hydrogenation step may be split into separate trains, asillustrated in FIGS. 1 and 2. One train may be provided for processingthe straight run middle cut (160-490° C., for example) of the crude oil,and a second train may be provided for processing the (490° C.− z, forexample) effluent from the residue hydrocracking reactor(s). Generally,the reactors 27 in the first destructive hydrogenation step may have aturnaround time longer than that of a steam cracking furnace, and aspare reactor may not be required to maintain uptime. The reactors 29 inthe second train may have more frequent turnarounds to replace catalyst,but it could have its feed redirected to the first train, such as via aflow line 37, during catalyst replacement, so it too would not require aspare reactor train for uptime. As a temporary diversion of feed, theimpact on reactor train 27 would be minimal, and thus reactor trains 27could be designed such that its turnarounds may be in sync with that ofthe steam cracker furnaces.

As noted above, various feedstocks may allow the cut points to beincreased, such as raising the mid/high cut point from 490° C. to 545°C. in some embodiments. The same may be true with respect to processingin the resid hydrocracking system, where higher boiling pointhydrocarbons may be able to be fed to the destructive hydrogenationreactor for conversion into feedstocks suitable for steam cracking.However, with respect to processing of the high boiling fraction (e.g.,490° C.+ or 545° C.+ fraction) in the resid hydrocracking system, it hasbeen found that a lower cut point may be more favorable, as a cut pointthat is too high may require the use of a cutter oil to produce theULSFO.

Referring now to FIG. 3, a simplified process flow diagram of a systemfor converting whole crudes and heavy hydrocarbons according toembodiments herein is illustrated.

A wide boiling range heavy hydrocarbon feed, such as a desalted crude10, may be fed to a separation system 12. Separation system 12 may be anintegrated separation device (ISD), as described above, for example. Inseparation system 12, the desalted crude 10 may be separated into threefractions, including (a) a light cut, such as a 160° C.− fraction 14,that doesn't require any conditioning and can be used as feed to thesteam cracker 16 and the aromatic complex unit 18; (b) a middle cut,such as a 160-490° C. fraction 20, that may be upgraded in a fixed bedconditioning section 22 to produce two types of lighter streams,including a highly paraffinic stream 24 suitable for the steam crackingsystem 16, which may produce light olefins stream 46, and a stream 26rich in aromatics that is suitable for aromatics production, which mayproduce aromatics stream 36, which may include benzene and para-xylenes;and, (c) a heavy cut, such as a 490° C.+ fraction 28, which contains themost refractory materials in the crude, which can be upgraded in anebullated bed resid hydrocracker 30. Other cut points may also be usedto route the desired fractions and hydrocarbons therein to desired unitsfor conditioning and/or cracking. The ebullated bed resid hydrocrackermay produce, for example, an ultra-low sulfur fuel oil 32 and a stream34 that is suitable to be fed to the fixed bed conditioning system toproduce the above mentioned two streams (the steam cracker feed 24 andthe aromatic complex feed 26). As noted above, streams 20 and 34 may beprocessed in separate conditioning trains to advantageously providesimilar life cycles of the catalysts and the steam cracker.

Other low value refinery streams may also be processed according toembodiments herein to produce ultimately higher value products. Suchstreams include some or all of the following types of hydrocarbons: (i)Light cycle oil (LCO), such as LCO that is produced from FCC unit, whichcan be fed via flow line 40 and processed in the fixed bed crudeconditioning section 22 along with the middle cut, such as a 160-490° C.fraction 20; (ii) a Slurry Oil, such as a slurry oil that is producedfrom an FCC unit, which can be fed via flow line 42 and processed in theebullated bed reactor 30 along with the heavy cut, such as 490° C.+hydrocarbons, in stream 28; (iii) Pitch, such as a pitch that isproduced from a solvent deasphalting unit, which can be fed via a sameor different flow line 42 and processed in the ebullated bed reactor 30along with the heavy cut (such as 490° C.+) hydrocarbons in stream 28;and/or (iv) a Pyrolysis fuel oil (Pyoil), such as a pyrolysis fuel oilthat is produced from a stream cracker, including pyrolysis fuel oilstream 44 from steam cracker 16, which stream can be processed in theebullated bed reactor 30 along with the heavy cut (e.g., 490° C.+)hydrocarbons in streams 28 and/or 42. Other various hydrocarbon streamsof similar boiling ranges may also be co-processed to producepetrochemicals in systems disclosed herein, where such streams mayinclude light naphthas, heavy naphthas, crude oils, atmosphericresidues, vacuum residues, synthetic crude oils, and other hydrocarbonstreams containing heavy hydrocarbons.

Following fixed bed conditioning of the middle cut fraction from stream20, the effluent stream from resid hydrocracking system 30, and/or theLCO from stream 40 in fixed bed conditioning reactor train(s) 22, thereactor effluent(s) 48 may be fed to a separation system 50, such as anISD, to recover a light boiling fraction 52 suitable for processing inthe steam cracker 16 and aromatics complex 18, as well as a heavyboiling fraction 54. Heavy boiling fraction 54 may be fed to the residhydrocracking system 30 for continued processing and conversion tolighter hydrocarbons, such as 490° C.− compounds. In some embodiments,separator 50 may provide a light fraction 52 having a cut point in therange from about 160° C. to about 220° C., and to provide a heavyfraction 54 having a corresponding lower cut point, such as 160° C.+ or220° C.+ hydrocarbons.

Similarly, following processing of the heavy cut, such as a 490° C.+fraction 28, in resid hydrocracking unit 30, the resid hydrocrackerreactor effluent 60 may be fed to a separation system 62, such as anISD, to recover a light boiling fraction 34 containing the conversionproducts suitable for processing in the fixed bed conditioning system22, as well as a heavy boiling fraction 64. Heavy boiling fraction 64may be fed to an integrated hydrotreater or hydrodesulfurization reactor66 to produce the ULSFO 32. In some embodiments, separator 62 mayprovide a light fraction 34 having a cut point in the range from about490° C. to about 520° C., and to provide a heavy fraction 64 having acorresponding cut point, such as 490° C.+ hydrocarbons.

The light boiling range fractions 14, 52 may be fed to a separator 58for separation of the components into a light naphtha fraction 24 and aheavy naphtha fraction 26, for example. The light naphtha rangecomponents may then be processed in the steam cracker system 16 forproducing petrochemicals, while the heavy naphtha range components maybe processed in aromatics complex 18 to produce benzene, toluene, andxylenes, for example.

In some embodiments, the heavy naphtha 26 fraction may undergo treatmentupstream of aromatics complex 18, such as a hydrogen sulfide treater(not illustrated) to further prepare the feed for conversion in thearomatics complex. Likewise, pyrolysis oil stream 44 may undergo apyrolysis oil stabilization step (corresponding flow block not shown)before processing in the resid hydrocracking reactor.

As described briefly above, embodiments herein may allow for the directcracking of crude oil to petrochemicals, forming light hydrocarbons likeethylene, propylene and light aromatics, in an economically viablemanner, without passing through the conventional refining steps.Additionally, direct conversion of crude oil to petrochemicals may helpclose the widening supply-demand gap for key building blocks normallyproduced as co-products (propylene, butadiene) due to the increasingshift toward cracking lighter feedstock spurred by the shale gasrevolution.

Integration of processing units according to embodiments herein mayprovide the unique potential for upgrading whole crudes, such as ArabLight crude and Arab Extra Light crude, along with low value refinerystreams, such as Pyrolysis Oil (PyOil), slurry oil and Light Cycle Oil(LCO), into higher value petrochemical products. While conditioning ofthe feeds according to embodiments herein adds hydrogen to the feedcomponents, and the hydrogen consumption is an added expense to theplant, the overall benefits in producing petrochemicals, rather thanfuels, outweighs this added expense. The aforementioned would also beapplicable to other types of crude, such as desalted oils, condensate,biogenic oil, synthesis crude, tight oil, heavy hydrocarbons,reconstituted crudes, and bitumen derived oils.

In various embodiments, an aromatics complex may be included, as notedabove. For example, an aromatics complex may be used to convert the 160°C.-490° C. fraction, or a portion thereof, to aromatics. For example, acut such as a 160° C. to 240° C. fraction may be processed to convert aportion of the hydrocarbons therein to aromatics, while the heavies maybe fed to the steam cracker for conversion to petrochemicals. Thearomatics complex feedstock generated via initial processing andconditioning according to embodiments herein may permit variousprocessors to discontinue importing full range naphtha (FRN).

Further, in some embodiments, the pyrolysis oil generated in the steamcracking unit may be separated to recover a pyrolysis gasoline fraction,and one or more heavies fractions, such as a pyrolysis gas oil fractionand a pyrolysis fuel oil fraction. The lighter pyrolysis gasolinefaction may be fed to an aromatics unit, while the heavier fractions maybe used to form an ULSFO, as noted above.

Embodiments herein provide a strategic combination of crude feedpreparation, crude separation, crude conditioning, and steam crackingtechnology to maximize the yield of high value petrochemicals. The crudeconditioning section employs a combination of fixed bed hydroprocessingand liquid circulation, and ebullated or slurry bed residuehydrocracking to condition the crude into a suitable steam cracker feedand to upgrade the low value refinery streams. Embodiments herein mayachieve a yield of petrochemicals in the range of 60% to 90% of thewhole crude feedstock, for example.

As described above, after desalting, the crude may be segregated intothree cuts, including: a light cut (such as a 160° C.− stream), whichmay then be further separated into 90° C.− and 90-160° C. cuts to feed asteam cracking heater and aromatics complex, respectively); a mid-cut(such as a 160-490° C. stream); and a heavy cut (such as a 490° C.+stream). The light cut (such as a 160° C.− stream) does not requireupgrading, and thus can be directly routed as steam cracker and aromaticcomplex feedstock. The mid cut (160-490° C. stream, for example) iseasily handled in a fixed bed destructive hydrogenation/conditioningreaction system, in which the feed is hydrotreated and converted tonaphtha, making an ideal steam cracker feedstock 24 and an aromaticscomplex feedstock 26.

The heavy cut (490° C.+ stream, for example) contains the most difficultcompounds in the crude to be processed, inclduing asphaltenes, metals,and Conradson Carbon Residue (CCR). In fixed bed down-flow reactors, theconversion and catalyst run length are typically limited by the metals,CCR, and asphaltenes content in residue feeds, and which results inrapid fouling of catalyst and increase of pressure drop. Embodimentsherein may employ an upward flow expanded bed reactor to overcome thepressure drop issue and permit the process to operate with uninterruptedflow for long periods at high residue conversions. As such, the heavycut, for example a 490° C.+ stream, may be processed in some embodimentsin a liquid circulation, ebullated bed reactor, such as LC-FININGTechnology available from Lummus Technology LLC. LC-SLURRY reactortechnology available from Chevron Lummus Global may also be used tohandle even heavier streams, such as pitch.

The crude conditioning section may contain four reaction stages,including ebullated bed reactors (such as LC-FINING Reactors), first andsecond Stage Hydrocracking Reactors, and a Heavy Oil DestructiveHydrogenation Reactor. These four reaction stages may operate within asingle, common recycle gas circulation loop. Integration of these crudeconditioning stages accomplishes the key processing objectives ofupgrading low value refinery streams, eliminating the need to importfull range naphtha (FRN), and providing steam cracker feed forproduction of incremental ethylene, while minimizing hydrogenconsumption, investment and operating costs.

Referring now to FIG. 4, a simplified flow diagram of processes forproducing olefins and aromatics according to embodiments herein isillustrated, where like numerals represent like parts. As an exemplaryfeed, an Arab Light crude 100 may be processed to produce sufficientLight Naphtha (110) to produce incremental ethylene as part of stream118 in a mixed feed steam cracker (MFC) 120, in addition to a feedstock112 for an aromatics complex 122. Other feeds to the mixed feed steamcracker may include, for example, a Raffinate-2 stream 123, propane 124,reactive organic gas (ROG) 125, and the mixed feed steam cracker mayproduce PyOil 102, pyrolysis gasoil 127, mixed C4s 128, propylene 129,and ethylene 118, among other products. FIG. 4 provides an overallprocess sketch highlighting the major equipment and stream routing ofone possible configuration according to embodiments herein. While ArabLight is given as an example, the aforementioned would also beapplicable to other types of crude, such as desalted oils, condensate,biogenic oil, synthesis crude, tight oil, heavy hydrocarbons,reconstituted crudes, and bitumen derived oils.

The feed streams to the feed conditioning section 101 may include, forexample, an Arab Light Crude Oil 100, a pyrolysis oil 102 (PyOil), suchas may be produced in the mixed feed cracker 120, a slurry oil 104, anda light cycle oil 106 (LCO). Embodiments herein, such as illustrated inFIG. 4, may produce the following products from the conditioningsection: Steam Cracker Feedstock (such as 90° C.− hydrocarbons) 110;Aromatics Complex Feedstock (such as 90-160° C. hydrocarbons) 112; andUltra Low Sulfur Fuel Oil (ULSFO) 114. Conditioning may also result inthe generation of various byproducts, such as Fuel Gas, Sour Water, RichAmine, and Desalter Brine, and may require the utilities such asHydrogen, Stripped Sour Water, Lean Amine, Steam, Power, Cooling Water,Fuel Gas, Nitrogen, BFW, and a Feed Preparation Section, which mayinclude desalting (each not illustrated).

Similar to other embodiments herein, the desalted crude 100 mayinitially be fed to a separator, such as an ISD 12. In separation system12, the desalted crude 100 may be separated into three fractions,including (a) a light cut, such as a 160° C.− fraction 14, (b) a middlecut, such as a 160-490° C. fraction 20, that may be upgraded in a fixedbed conditioning section 22, which may include fixed bed hydrotreatingand/or hydrocracking reactors, and (c) a heavy cut, such as a 490° C.+fraction 28, which contains the most refractory materials in the crudeand which can be upgraded in an ebullated bed resid hydrocracker 30.

The conditioned compounds, such as 490° C.− compounds produced in residhydrocracker 30, may be fed via stream 34 for further conditioning inconditioning section 22. If desired, other full range naphtha feedstocksmay be fed to the aromatics plant, such as via flow line 105.

Referring now to FIG. 5, a desalted crude oil 100 may be separated, in afirst Integrated Separation Device (ISD) 158, to recover a 160° C.−fraction 113. The integrated separation device 158 may operate, forexample, at 200° C. and 8 barg, to enhance the vapor liquid separationefficiency. The ISD overhead vapor product 113 (such as a 160° C.−fraction cut of the crude oil) is routed to a product splitter 160. Inthe product splitter 160, the 160° C.− hydrocarbons, along with thehydrotreated product 316, or a portion thereof, may be separated intolight (such as a 30° C.− or a 35° C.−) stream 120 a light naphtha stream(e.g., a 30-90° C. stream) 120, and a heavy naphtha (e.g., 90-160° C.)stream 122. The light stream 110 and light naphtha stream 120 may thenbe used as a steam cracker 111 feedstock to make an incremental amountof ethylene, or other product petrochemicals 113. The heavy naphtha 122may be used as the feedstock 122A to the aromatics complex 112. In someembodiments, at least a portion 112B of the heavy naphtha 122 may becombined with the light naphtha 120 and fed to the steam cracker forproduction of additional petrochemicals 113 and/or pyoil 191. In otherembodiments, all of the heavy naphtha 122 may be fed to the steamcracker 111 when the aromatics complex needs to be taken offline forservicing, or when there is insufficient benzene, toluene, and/orxylenes (BTX) in streams 113 and/or 316. Heavy naphtha feed routing mayalso be based on demand, for example.

The remaining 160° C.+ crude fraction 114 from the ISD 158 may be fed toa second separation system, such as a hot hydrogen stripper 166, wherethe 160° C.+ crude fraction is further separated into a mid-cut, such asa 160-490° C. fraction 168, and a heavy cut, such as a 490° C.+ fraction170.

The heavy cut 170 (such as a 490° C.+ cut) contains the most difficultcompounds which must be handled in the crude, including asphaltenes,metals, and CCR. The excessive amount of metals, CCR, and asphaltenes inthe high boiling residue fraction may lead to rapid fouling of catalystand increase of pressure drop in fixed bed down-flow reactors, limitingboth conversion and catalyst run length. Employment of an upward flowexpanded bed reactor may overcome the pressure drop issue and permitsthe process to operate with uninterrupted flow for long periods at highresidue conversions. As such, the heavy cut, 490° C.+ stream, 170 may beprocessed in a liquid circulation, ebullated bed reactor system 200 insome embodiments.

The heavy cut 170 may be processed in the ebullated bed reactor system200 together with one or more additional feeds, such as a slurry oil 192and/or a pyoil 191. In some embodiments, the ebullated bed reactorsystem 200 may include a first ebullated bed reactor and a secondebullated bed reactor. In embodiments where not all of the pyoil 191 isrecycled to the ebullated bed reactor system 200, pyoil may be removedfrom the system via stream 193.

The ebullated bed reactor system effluent 202 may be flashed in a HighPressure High Temperature (HP/HT) Separator 204. The vapor 206 from theHP/HT separator 204 may be combined with one or more of the mid-cut 168from the second ISD 166, vapor 208 from a Heavy Oil Hydrotreating(HOHDT) HP/HT separator 210, and fed to the first stage fixed bedcondition section 176. The liquid 214 from HP/HT separator 204 may beprocessed in a heavy oil destructive hydrogenation reactor 222. Theheavy oil destructive hydrogenation reactor effluent 223 may beseparated in the HOHDT separator 210. HOHDT liquid effluent 115 may becombined with a portion of product separator bottoms 300 (300A) toproduce an ULSFO product 301.

The main objective of the first stage reaction system 176 is tohydrotreat the blended feed to reduce feed sulfur and nitrogen levels,partially convert to product, and prepare the feed for furtherprocessing in the second stage reactor 178. The liquid feed to the firststage reaction system 176 may be a blend of straight-run (SR), mid-cut,160-490° C. crude fraction 166, the ebullated bed reactor distillateproducts 206, vapor 208 from the HOHDT separator 210, and LCO 106.

To meet the processing objective of removing feed sulfur and nitrogenand partially converting into a suitable steam cracker feedstock, thefirst stage reactor 176 may be loaded with a catalyst system consistingof demetalization, destructive hydrogenation, and hydrocrackingcatalysts. In order to control the temperature rise due to exothermicreactions, the catalysts may be separated into multiple beds within thereactor or into separate reactor vessels. Cold recycle gas (notillustrated) may be introduced between the beds or reactors to quenchthe reacting fluids and control the amount of temperature rise and rateof reaction.

The first stage reactor effluent 250 may consist of unconverted oil,distillates, naphtha, light ends, and excess hydrogen not consumed inthe first state reactor 176. The first state reactor effluent stream 250may be fed to a High Pressure Low Temperature (HP/LT) Separator 266. Anyrecovered sour water 274, containing NH₃ and/or H₂S, may be removed fromthe system. The hydrogen rich vapor 276 from the HP/LT separator 266 maybe sent to a gas compression and distribution system 277. The gascompression and distribution system may clean and pressurize thehydrogen, and recycle the hydrogen gas to a common hydrogen header 400.While not illustrated, hydrogen in the common hydrogen header 400 may befed to one or more of the ebullated bed conditioning system 200, firststage reaction system 176, second stage reaction system 178, heavy oildestructive hydrogenation reactor 222.

The hydrocarbon liquid 290 exiting the HP/LT separator 266 may be pumpedto the second stage reaction section 178 for further conditioning,targeting maximum naphtha production. The objective of the second-stagereaction system 178 is to crack unconverted oil (UCO) from the firststage reaction section into lighter products. As such, the second stagereactor may be loaded with highly active hydrocracking catalyst. Aportion of the product separator bottoms 300 (300B) may also be fed tothe second stage reaction system 178 for additional conditioning.

The second stage reactor effluent 180 may be fed to a High Pressure LowTemperature (HP/LT) separator 314. The HP/LT liquid product 316 may befed to the product splitter 160, and the vapor product 320 mixes withthe hydrogen rich vapor 276 in the gas compression and distributionsystem 277. The recovered hydrogen and fresh hydrogen, if necessary, maythen be routed from the gas compression and distribution system 277 tothe various conditioning reactors as needed.

The 160° C.− product 113 from the integrated separation device 158 alongwith the HP/LT liquid product 316 may be fed into the product splitter160. The product splitter 160 may separate the reactor effluent productsinto light fraction 110, a light naphtha fraction 120, and a heavynaphtha 122. The light naphtha product 110 is routed as feedstock to thesteam cracker 111.

Heavy Naphtha product 122 may be taken as a side draw from the productsplitter 160. A portion 112A of the heavy naphtha product 122 may pumpedto the aromatics complex 112, and a portion 112B of the heavy naphthaproduct 122 may combined with the light naphtha fraction 120 and fed tothe stream cracker 111.

As described with respect to FIGS. 1 and 2, separation system 3 may beas illustrated in FIG. 6. Separation system 3 may be as described aboveand including separation and heat integration. After desalting, thecrude 1 may be further preheated in the convection section of a heater500 to produce a preheated crude 502. The preheated crude 502 may thenbe fed to a separator 504, which may facilitate the separation of the160° C.− fraction 5 from heavier components, recovered in stream 506.

The remaining 160° C.+ crude fraction 506 may be fed to a pump 508,which produces a pressurized 160° C.+ crude fraction 510, which may thenbe fed to a heat exchanger 512. Heat exchanger 512 may preheat the 160°C.+ crude fraction 510 against hot hydrogen stripper bottoms 520,producing a pressurized and pre-heated 160° C.+ crude fraction 514. Thepressurized and pre-heated 160° C.+ crude fraction 514 may then be fedback to the heater 500, where it is heated to facilitate the separationof a 160-490° C. fraction from a heavier 490° C.+ fraction. The heated160° C.+ crude fraction 516 may then be fed to a hot hydrogen stripper518. In the hot hydrogen stripper 518, the 160° C.+ crude fraction isfurther separated into a 160-490° C. fraction 9 and the hot hydrogenstripper bottoms 520, which contains heavier 490° C.+ hydrocarbons. Thehot hydrogen stripper bottoms 520, after being cooled via indirect heatexchange in heat exchanger 512 against the pressurized 160° C.+ crudefraction 510, may be removed from the separation system 3 as the 490°C.+ fraction 15.

The hot hydrogen stripper 518 may utilize a hydrogen feed 522 as thestripping medium. The hot hydrogen stripper 518 may be operated toprovide broad flexibility, based on the nature of the crude feedstockthat is being processed. The stripper overheads, which is the 160-490°C. fraction 9, may be cooled, to recover hydrogen, and routed to theintermediate hydroproces sing reaction stages as appropriate, and asdescribed with respect with FIGS. 1 and 2. The recovered hydrogen may befed to a downstream pressure swing adsorption (PSA) unit (not shown),after amine treatment (not shown), to improve the hydrogen purity. ThePSA hydrogen product may be compressed in a make-up hydrogen compressor(not shown) to provide the make-up hydrogen for the one or morehydroprocessing reactors (FIGS. 1 and 2), and as hot hydrogen feed 522.

The hot hydrogen stripper bottoms product 520 (such as a 490° C.+ cut)contains the most difficult compounds which must be handled in thecrude, including asphaltenes, metals, and CCR. The excessive amount ofmetals, CCR, and asphaltenes in the high boiling residue fraction leadsto rapid fouling of catalyst and increase of pressure drop in fixed beddown-flow reactors, limiting both conversion and catalyst run length.After cooling against the pressurized 160° C.+ crude fraction 510, the490° C.+ stream 11 may be recovered and processed in a liquidcirculation, ebullated bed residue hydrocracker, as described in FIGS. 1and 2, along with any additional low value refinery streams, such as apyoil stream and/or slurry oil stream.

By adjusting the amount of hydrogen 522 fed to the hot hydrogen stripper518, as well as the operating conditions of the hot hydrogen stripper518 and heater 500, the hydrocarbon cut points may be adjusted such thatthe light-cut 5 may be fed directly to the downstream steam cracker, andthe mid-cut 9 may have little to no deleterious compounds that wouldrapidly foul the fixed bed conditioning reactors. In this way, theseparation system 3 (with the hot hydrogen stripper 518) may concentratethe most difficult to process hydrocarbons in the heavy-cut 11, whichmay be fed to the ebullated bed reactors operating at severe conditions.

As described with respect to FIGS. 3 and 4, separation system 12 may bea separation system as illustrated in FIG. 7. Separation system 312 maybe as described above and including separation and heat integration.After desalting, the crude 100 may be further preheated in theconvection section of a heater 500 to produce a preheated crude 502. Thepreheated crude 502 may then be fed to a separator 504, which mayfacilitate the separation of the 160° C.− fraction 5 in the integratedseparation system 3.

The remaining 160° C.+ crude fraction 506 may be fed to a pump 508,which produces a pressurized 160° C.+ crude fraction 510, which may thenbe fed to a heat exchanger 512. Heat exchanger 512 may preheat the 160°C.+ crude fraction 510 against hot hydrogen stripper bottoms 520,producing a pressurized and pre-heated 160° C.+ crude fraction 514. Thepressurized and pre-heated 160° C.+ crude fraction 514 may then be fedback to the heater 500 where it is heated to facilitate the separationof a 160-490° C. fraction from a heavier 490° C.+. The heated 160° C.+crude fraction 516 may then be fed to a hot hydrogen stripper 518. Inthe hot hydrogen stripper 518, the 160° C.+ crude fraction is furtherseparated into a 160-490° C. fraction 20 and the hot hydrogen stripperbottoms 520, which contains heavier 490° C.+ hydrocarbons. The hothydrogen stripper bottoms 520, after being cooled via indirect heatexchange in heat exchanger 512 against the pressurized 160° C.+ crudefraction 510, may be removed from the separation system 3 as the 490°C.+ fraction 28.

The hot hydrogen stripper 518 may utilize a hydrogen feed 522 as thestripping medium. The hot hydrogen stripper 518 may be operated toprovide broad flexibility, based on the nature of the crude feedstockthat is being processed. The stripper overheads, which is the 160-490°C. fraction 20, may be cooled, to recover hydrogen, and routed to theintermediate hydroproces sing reaction stages as appropriate, and asdescribed with respect with FIGS. 3 and 4. The recovered hydrogen may befed to a downstream pressure swing adsorption (PSA) unit (not shown),after amine treatment (not shown), to improve the hydrogen purity. ThePSA hydrogen product may be compressed in a make-up hydrogen compressor(not shown) to provide the make-up hydrogen for the one or morehydroprocessing reactors (FIGS. 3 and 4), and as hot hydrogen feed 522.

The hot hydrogen stripper bottoms product 520 (such as a 490° C.+ cut)contains the most difficult compounds which must be handled in thecrude, including asphaltenes, metals, and CCR. The excessive amount ofmetals, CCR, and asphaltenes in the high boiling residue fraction leadsto rapid fouling of catalyst and increase of pressure drop in fixed beddown-flow reactors, limiting both conversion and catalyst run length.After cooling against the pressurized 160° C.+ crude fraction 510, the490° C.+ stream 28 may be recovered and processed in a liquidcirculation, ebullated bed residue hydrocracker, as described in FIGS. 3and 4, along with any additional low value refinery streams, such as apyoil stream and/or slurry oil stream.

By adjusting the amount of hydrogen 522 fed to the hot hydrogen stripper518, as well as the operating conditions of the hot hydrogen stripper518 and heater 500, the hydrocarbon cut points may be adjusted such thatthe light-cut 5 may be fed directly to the downstream steam cracker, andthe mid-cut 20 may have little to no deleterious compounds that wouldrapidly foul the fixed bed conditioning reactors. In this way, theseparation system 12 (with the hot hydrogen stripper 518) mayconcentrate the most difficult to process hydrocarbons in the heavy-cut28 which may be fed to the ebullated bed reactors.

With respect to FIGS. 1-7 described above, the light-, mid-, andheavy-cut fractions are given with limited examples of 160° C.−, 160°C.−490° C., and 490° C.+. The cut points may be adjusted such that thelight-cut may be fed directly to the steam cracker with little to nointermediate processing, and the mid- and heavy-cuts can be effectivelyprocessed within their respective reactor trains.

Steam crackers, including ethylene complexes, useful in embodimentsherein may include various unit operations. For example, an ethylenecomplex may include a cracker, such as a steam cracker. Other crackingoperations may also be used. The ethylene complex may also include anolefins recovery unit, a butadiene extraction unit, a MTBE unit, a C4selective hydrogenation unit, a pyrolysis gasoline hydrotreating unit,an aromatics extraction unit, a metathesis unit, and/or adisproportionation unit, among others useful for the production andrecovery of olefins and other light hydrocarbons. Products from theethylene complex may include, for example, ethylene, propylene,butadiene, benzene, MTBE, and mixed xylenes, among others.

In some embodiments, the hydrocarbon streams to be cracked may be feddirectly to the steam cracker. In other embodiments, the hydrocarbonstreams noted above to be cracked may be separated into multiplefractions for separate processing (cracking, for example, at preferredtemperatures, pressures, and residence times for each respectivefraction).

The hydrocarbon feedstocks, which may be a single hydrocarbon or amixture of hydrocarbons, may be introduced to a heating coil disposed inthe convection section of a steam pyrolysis heater. In the heating coil,the hydrocarbon feedstock may be heated and/or vaporized via convectiveheat exchange with the exhaust.

If desired, the heated hydrocarbon feedstock may then be mixed withsteam or an inert compound, such as nitrogen, carbon dioxide, or anyother inorganic gases. Various portions of the process or additionalprocesses in the plant may use low temperature or saturated steam, whileothers may use high temperature superheated steam. Steam to be usedwithin the process or elsewhere in the plant may be heated orsuperheated via a heating coil (not shown) disposed in the convectionzone of a steam pyrolysis heater.

The heated hydrocarbon mixture(s) may then be fed to a heating coil,which may be disposed at a lower elevation in the steam pyrolysisheater, and therefore at a higher temperature, than the convective zoneheating coil noted above. The resulting superheated mixture may then befed to one or more coils disposed in a radiant zone of the steampyrolysis heater, operated at a temperature for partial conversion, viathermal cracking, of the hydrocarbon mixture. The cracked hydrocarbonproduct may then be recovered.

In some embodiments, multiple heating and separation steps may be usedto separate the hydrocarbon mixture(s) to be cracked into two or morehydrocarbon fractions, if desired. This will permit conditioning andsteam cracking of each cut optimally, such that the throughput, steam tooil ratios, heater inlet and outlet temperatures and other variables maybe controlled at a desirable level to achieve the desired reactionresults, such as to a desired product profile while limited coking inthe radiant coils and associated downstream equipment. As various cuts,depending upon the boiling point of the hydrocarbons in the various feedstreams, are separated and cracked, the coking in the radiant coils andtransfer line exchangers can be controlled. As a result, the run lengthof the heater may be increased to many weeks, instead of few hours, withhigher olefin production.

Following cracking in the radiant coils, one or more transfer lineexchangers may be used to cool the products very quickly and generate(super) high pressure steam. One or more coils may be combined andconnected to each exchanger. The exchanger(s) can be double pipe ormultiple shell and tube exchanger(s).

Instead of indirect cooling, direct quenching can also be used. For suchcases, oil may be injected at the outlet of the radiant coil. Followingthe oil quench, a water quench can also be used. Instead of oil quench,an all water quench is also acceptable. After quenching, the productsare sent to a recovery section.

As described above, embodiments herein may separate a desalted crude orother wide boiling hydrocarbons into various fractions to effectivelycondition the respective fractions to form a feedstock suitable forconversion in a steam cracker. Because of the wide range of feedstocksthat may be processed according to embodiments herein, depending uponthe feedstock, conditioning catalysts, reactor volumes, and otherfactors for a given installation, it may be more preferential to basethe specific cut points based on one or more additional properties ofthe feedstock. For example, the specific cut points may be adjustedbased on one or more properties or additional properties of the crudefeedstock, such as API gravity, Bureau of Mines Correlation Index(BMCI), hydrogen content, nitrogen content, sulfur content, viscosity,microcarbon residue (MCRT), and/or total metals, among other feedstockproperties.

Various feedstocks useful in embodiments herein, such as crude oils,desalted oils, condensate, biogenic oil, synthetic crude, tight oil,heavy hydrocarbons, reconstituted crude and bitumen derived oil may haveone or more of the following properties, including: an API gravitybetween 4 and 60°, a BMCI of 20 to 85, a hydrogen content of 9.0 to 14.5wt % (or 90,000 to 145,000 ppm), a nitrogen content of 0.02 to 0.95 wt %(or 200 to 9,500 ppm), a sulfur content of 0.009 to 6.0 wt % (or 90 to60,000 ppm), a viscosity, at 40° C., of 95 to 5500 centistokes (cSt), aMCRT of 5 to 35 wt %, and/or may have a total metals content of <1 to1000 ppm.

The initial crude separations may be conducted and adjusted in order tohave the light-, mid-, and heavy-cuts have specific, desirable initialproperties, such that the light-cut may go to the steam cracker with no,or minimal, intermediate processing. Further, the mid to heavy cuts maybe conducted and adjusted in order to have the mid-cut and heavy-cuthave appropriate and/or favorable feed properties and hydrocarbonspecies so as to be effectively and efficiently conditioned in the midand heavy conditioning reactors.

BMCI

In some embodiments, the light cut may have a BMCI of less than 20. Inother embodiments, the light cut may have a BMCI of less than 15. In yetother embodiments, the light cut may have a BMCI of less than 10 or evenless than 5. In some embodiments, the mid cut may have a BMCI of lessthan 40, such as less than 35, less than 30, or less than 25. In someembodiments, the heavy cut may have a BMCI of greater than 30, such asgreater than 35, greater than 40, greater than 45, greater than 50, orgreater than 55.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 90° C. to about 300° C., for example,may have a BMCI of less than 20; in other embodiments, such as when thelight cut includes hydrocarbons having a boiling point up to about 110°C. or up to about 250° C., for example, the light cut may have a BMCI ofless than 10; in yet other embodiments, such as when the light cutincludes hydrocarbons having a boiling point up to about 130° C. or upto about 220° C., for example, the light cut may have a BMCI of lessthan 5. In some embodiments where the light cut includes hydrocarbonshaving a boiling point below about 160° C., the light cut may have aBMCI of less than 5. While the BMCI may vary for the different feeds atany given cut temperature, a low BMCI, such as less than 10 or less than5, for example, has been found to improve the processability of thelight hydrocarbons in the steam pyrolysis unit without the need forintermediate processing. Light cuts for Arab light crudes processedaccording to embodiments herein may target a BMCI of less than 10, forexample, and may target a BMCI of less than 6 or less than 5.5 for Arabextra light crudes, for example.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a BMCI of between about 5 and 50. For example, the mid cut mayhave a BMCI of between a lower limit of 5, 10, 15, 20, or 25 to an upperlimit of 10, 15, 20, 25, 30, 40, or 50. A mid-cut having a BMCI ofbetween 10 and 30, for example, has been found to be convertible tosteam cracker feeds using relatively moderate destructive hydrogenationconditions in the mid-cut conditioning section of processes herein.Mid-cuts for Arab light crudes processed according to embodiments hereinmay target a BMCI in the range from about 20 to about 30, for example,and may target a BMCI in the range from about 15 to about 30 for Arabextra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a BMCI of greaterthan 30. When the heavy cut includes hydrocarbons having a boiling pointabove about 350° C., the heavy cut may have a BMCI of greater than 40.When the heavy cut includes hydrocarbons having a boiling point aboveabout 400° C., the heavy cut may have a BMCI of greater than 50. Inembodiments where the heavy cut includes hydrocarbons having a boilingpoint above about 490° C., the heavy cut may have a BMCI of greater than55. A heavy-cut having a BMCI of greater than about 40, for example, hasbeen found to be convertible to steam cracker feeds using the moresevere destructive hydrogenation conditions in the heavy-cutconditioning section of processes herein. Heavy-cuts for Arab lightcrudes processed according to embodiments herein may target a BMCI inthe range from about 50 to about 60, for example, and may target a BMCIin the range from about 25 to about 40 for Arab extra light crudes, forexample.

API

In some embodiments, the light cut may have an API gravity of greaterthan 10°. In other embodiments, the light cut may have an API gravity ofgreater than 15°. In yet other embodiments, the light cut may have anAPI gravity of greater than 20°, greater than 30°, or even greater than40°. In some embodiments, the mid cut may have an API gravity of greaterthan 10° and less than 40°, such as from a lower limit of 10°, 15°, 20°,25°, or 30° to an upper limit of 25°, 30°, 35°, 40°, 45°, or 50°. Insome embodiments, the heavy cut may have an API gravity of less than40°, such as less than 35°, less than 25°, less than 20°, less than 15°,or less than 10°.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have an APIgravity of greater than 10°; in other embodiments, such as when thelight cut includes hydrocarbons having a boiling point up to about 250°C., for example, the light cut may have an API gravity of greater than20°; in yet other embodiments, such as when the light cut includeshydrocarbons having a boiling point up to about 220° C., for example,the light cut may have an API gravity of greater than 40°. In someembodiments where the light cut includes hydrocarbons having a boilingpoint below about 160° C., the light cut may have a API gravity ofgreater than 60°. While the API gravity may vary for the different feedsat any given cut temperature, an API gravity, such as greater than 40°,greater than 50°, or greater than 60°, for example, has been found toimprove the processability of the light hydrocarbons in the steampyrolysis unit without the need for intermediate processing. Light cutsfor Arab light crudes processed according to embodiments herein maytarget an API gravity of greater than 65°, for example, and may targetan API gravity of greater than 60° for Arab extra light crudes, forexample.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have an API gravity of between about 5° and 50°. For example, themid cut may have a API gravity of between a lower limit of 5°, 10°, 15°,20°, or 25° to an upper limit of 10°, 15°, 20°, 25°, 30°, 40°, or 50°. Amid-cut having a API gravity of between 20° and 40°, for example, hasbeen found to be convertible to steam cracker feeds using relativelymoderate destructive hydrogenation conditions in the mid-cutconditioning section of processes herein. Mid-cuts for Arab light crudesprocessed according to embodiments herein may target an API gravity inthe range from about 30° to about 35°, for example, and may target anAPI gravity in the range from about 35° to about 40° for Arab extralight crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have an API gravity ofless than about 40°. When the heavy cut includes hydrocarbons having aboiling point above about 350° C., the heavy cut may have an API gravityof less than about 20°. When the heavy cut includes hydrocarbons havinga boiling point above about 400° C., the heavy cut may have an APIgravity of less than about 10°. In embodiments where the heavy cutincludes hydrocarbons having a boiling point above about 490° C., theheavy cut may have an API gravity of less than 7°, for example. Aheavy-cut having an API gravity of less than about 20°, for example, hasbeen found to be convertible to steam cracker feeds using the moresevere destructive hydrogenation conditions in the heavy-cutconditioning section of processes herein. Heavy-cuts for Arab lightcrudes processed according to embodiments herein may target an APIgravity in the range from about 5° to about 10°, for example, and maytarget an API gravity in the range from about 10° to about 20° for Arabextra light crudes, for example.

Hydrogen Content

In some embodiments, the light cut may have a hydrogen content ofgreater than 12 wt %. In other embodiments, the light cut may have ahydrogen content of greater than 13 wt %. In yet other embodiments, thelight cut may have a hydrogen content of greater than 13.5 wt %, greaterthan 14 wt %, or even greater than 15 wt %. In some embodiments, the midcut may have a hydrogen content of greater than 11 wt % and less than 14wt %, such as from a lower limit of 11, 11.5, 12.0, 12.5, or 13.0 wt %to an upper limit of 12.0, 12.5, 13.0, 13.5, 14.0, or 14.5 wt %. In someembodiments, the heavy cut may have a hydrogen content of less than 13wt %, such as less than 12.5 wt %, less than 12 wt %, less than 11.5 wt%, or less than 11 wt %.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have anhydrogen content of greater than 13 wt %; in other embodiments, such aswhen the light cut includes hydrocarbons having a boiling point up toabout 250° C., for example, the light cut may have an hydrogen contentof greater than 13.5 wt %; in yet other embodiments, such as when thelight cut includes hydrocarbons having a boiling point up to about 220°C., for example, the light cut may have an hydrogen content of greaterthan 14.0 wt %. In some embodiments where the light cut includeshydrocarbons having a boiling point below about 160° C., the light cutmay have a hydrogen content of greater than 14.5 wt %. While thehydrogen content may vary for the different feeds at any given cuttemperature, a hydrogen content, such as greater than 13 wt %, greaterthan 14 wt %, or greater than 14.5 wt %, for example, has been found toimprove the processability of the light hydrocarbons in the steampyrolysis unit without the need for intermediate processing. Light cutsfor Arab light crudes processed according to embodiments herein maytarget a hydrogen content of greater than 14.5 wt %, for example, andmay target a hydrogen content of greater than 14 wt % for Arab extralight crudes, for example.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a hydrogen content of between about 11.5 wt % and 14.5 wt %. Amid-cut having a hydrogen content of between 12 wt % and 13.5 wt %, forexample, has been found to be convertible to steam cracker feeds usingrelatively moderate destructive hydrogenation conditions in the mid-cutconditioning section of processes herein. Mid-cuts for Arab light crudesprocessed according to embodiments herein may target a hydrogen contentin the range from about 12.5 wt % to about 13.5 wt %, for example, andmay target an hydrogen content in the range from about 13.0 wt % toabout 14.0 wt % for Arab extra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a hydrogen content ofless than about 13 wt %. When the heavy cut includes hydrocarbons havinga boiling point above about 350° C., the heavy cut may have a hydrogencontent of less than about 12.5 wt %. When the heavy cut includeshydrocarbons having a boiling point above about 400° C., the heavy cutmay have a hydrogen content of less than about 12.0 wt %. In embodimentswhere the heavy cut includes hydrocarbons having a boiling point aboveabout 490° C., the heavy cut may have a hydrogen content of less than 11wt %, for example. A heavy-cut having a hydrogen content of less thanabout 12 wt %, for example, has been found to be convertible to steamcracker feeds using the more severe destructive hydrogenation conditionsin the heavy-cut conditioning section of processes herein. Heavy-cutsfor Arab light crudes processed according to embodiments herein maytarget a hydrogen content in the range from about 10 wt % to about 11 wt%, for example, and may target a hydrogen content in the range fromabout 11 wt % to about 12 wt % for Arab extra light crudes, for example.

Nitrogen Content

In some embodiments, the light cut may have a nitrogen content of lessthan 100 ppm, such as less than 50 ppm or less than 30 ppm. In otherembodiments, the light cut may have a nitrogen content of less than 25ppm. In yet other embodiments, the light cut may have a nitrogen contentof less than 20 ppm, less than 15 ppm, less than 10 ppm, less than 5ppm, less than 3 ppm, less than 1 ppm, or even less than 0.5 ppm. Insome embodiments, the mid cut may have a nitrogen content of greaterthan 1 ppm and less than 1000 ppm, such as from a lower limit of 1, 5,10, 50, 100, 250, or 500 ppm to an upper limit of 50, 100, 250, 500, or1000 ppm. In some embodiments, the heavy cut may have a nitrogen contentof greater than 10 ppm, such as greater than 25 ppm, greater than 50ppm, greater than 100 ppm, greater than 150 ppm, greater than 200 ppm,greater than 250 ppm, greater than 500 ppm, greater than 1000 ppm,greater than 1500 ppm, greater than 2000 ppm, or greater than 2500 ppm.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have annitrogen content of less than 0.01 wt %, or 100 ppm; in otherembodiments, such as when the light cut includes hydrocarbons having aboiling point up to about 250° C., for example, the light cut may havean nitrogen content of less than 0.001 wt %, or 10 ppm; in yet otherembodiments, such as when the light cut includes hydrocarbons having aboiling point up to about 220° C., for example, the light cut may have anitrogen content of less than 0.0001 wt %, or 1 ppm. In some embodimentswhere the light cut includes hydrocarbons having a boiling point belowabout 160° C., the light cut may have a nitrogen content of less thanabout 0.00003 wt %, or 0.3 ppm. While the nitrogen content may vary forthe different feeds at any given cut temperature, a nitrogen content,such as less than about 100 ppm, less than 10 ppm, or less than 1 ppm,for example, has been found to improve the convertibility of the lighthydrocarbons in the steam pyrolysis unit without the need forintermediate processing. Light cuts for Arab light crudes processedaccording to embodiments herein may target a nitrogen content of lessthan 1 ppm, for example, and may also target a nitrogen content of lessthan 1 ppm for Arab extra light crudes, for example.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a nitrogen content of between about 10 ppm and 250 ppm, forexample. A mid-cut having a nitrogen content of between 20 and 250 ppm,for example, has been found to be convertible to steam cracker feedsusing relatively moderate destructive hydrogenation conditions in themid-cut conditioning section of processes herein. Mid-cuts for Arablight crudes processed according to embodiments herein may target anitrogen content in the range from about 200 to about 300 ppm, forexample, and may target an nitrogen content in the range from about 100to about 150 ppm for Arab extra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a nitrogen content ofgreater than about 0.001 wt %, or 10 ppm. When the heavy cut includeshydrocarbons having a boiling point above about 350° C., the heavy cutmay have a nitrogen content of greater than about 0.005 wt %, or 50 ppm.When the heavy cut includes hydrocarbons having a boiling point aboveabout 400° C., the heavy cut may have a nitrogen content of greater thanabout 0.01 wt %, or 100 ppm. In embodiments where the heavy cut includeshydrocarbons having a boiling point above about 490° C., the heavy cutmay have a nitrogen content of greater than 2500 ppm, for example. Aheavy-cut having a nitrogen content of greater than about 100 ppm, forexample, has been found to be convertible to steam cracker feeds usingthe more severe destructive hydrogenation conditions in the heavy-cutconditioning section of processes herein. Heavy-cuts for Arab lightcrudes processed according to embodiments herein may target a nitrogencontent in the range from about 2000 to about 3000 ppm, for example, andmay target a nitrogen content in the range from about 1000 to about 2000for Arab extra light crudes, for example.

Sulfur Content

In some embodiments, the light cut may have a sulfur content of lessthan 10000 ppm, such as less than 5000 ppm or less than 1000 ppm. Inother embodiments, the light cut may have a sulfur content of less than750 ppm. In yet other embodiments, the light cut may have a sulfurcontent of less than 500 ppm, less than 250 ppm, or even less than 100ppm. In some embodiments, the mid cut may have a sulfur content ofgreater than 500 ppm and less than 10000 ppm, such as from a lower limitof 500, 750, 1000, 1500, 2000, 2500, or 5000 ppm to an upper limit of1000, 2000, 5000, 10000, 15000, or 20000 ppm. In some embodiments, theheavy cut may have a sulfur content of greater than 1000 ppm, such asgreater than 2500 ppm, greater than 5000 ppm, greater than 10000 ppm,greater than 15000 ppm, greater than 20000 ppm, greater than 25000 ppm,greater than 30000 ppm, greater than 35000 ppm, greater than 40000 ppm,greater than 45000 ppm, or greater than 50000 ppm.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have ansulfur content of 1 wt %, or 10,000 ppm; in other embodiments, such aswhen the light cut includes hydrocarbons having a boiling point up toabout 250° C., for example, the light cut may have an sulfur content ofless than 0.5 wt %, or 5,000 ppm; in yet other embodiments, such as whenthe light cut includes hydrocarbons having a boiling point up to about220° C., for example, the light cut may have a sulfur content of lessthan 0.1 wt %, or 1,000 ppm. In some embodiments where the light cutincludes hydrocarbons having a boiling point below about 160° C., thelight cut may have a sulfur content of less than about 750 ppm or lessthan 500 ppm. While the sulfur content may vary for the different feedsat any given cut temperature, a sulfur content, such as less than about600 ppm, for example, has been found to improve the convertibility ofthe light hydrocarbons in the steam pyrolysis unit without the need forintermediate processing. Light cuts for Arab light crudes processedaccording to embodiments herein may target a sulfur content of less than750 ppm, for example, and may also target a sulfur content of less than500 ppm for Arab extra light crudes, for example.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a sulfur content of between about 1000 ppm and 20000 ppm, forexample. A mid-cut having a sulfur content of between 2000 and 15000ppm, for example, has been found to be convertible to steam crackerfeeds using relatively moderate destructive hydrogenation conditions inthe mid-cut conditioning section of processes herein. Mid-cuts for Arablight crudes processed according to embodiments herein may target asulfur content in the range from about 6000 to about 12000 ppm, forexample, and may target an sulfur content in the range from about 5000to about 10000 ppm for Arab extra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a sulfur content ofgreater than about 0.1 wt %, or 1,000 ppm. When the heavy cut includeshydrocarbons having a boiling point above about 350° C., the heavy cutmay have a sulfur content of greater than about 0.5 wt %, or 5,000 ppm.When the heavy cut includes hydrocarbons having a boiling point aboveabout 400° C., the heavy cut may have a sulfur content of greater thanabout 1 wt %, or 1,0000 ppm. In embodiments where the heavy cut includeshydrocarbons having a boiling point above about 490° C., the heavy cutmay have a sulfur content of greater than 25000 ppm, for example. Aheavy-cut having a sulfur content of greater than about 10000 ppm, forexample, has been found to be convertible to steam cracker feeds usingthe more severe destructive hydrogenation conditions in the heavy-cutconditioning section of processes herein. Heavy-cuts for Arab lightcrudes processed according to embodiments herein may target a sulfurcontent in the range from about 30000 to about 50000 ppm, for example,and may target a sulfur content in the range from about 20000 to about30000 for Arab extra light crudes, for example.

Viscosity

In some embodiments, the light cut may have a viscosity, measured at 40°C. according to ASTM D445, of less than 10 cSt. In other embodiments,the light cut may have a viscosity, measured at 40° C., of less than 5cSt. In yet other embodiments, the light cut may have a viscosity,measured at 40° C., of less than 1 cSt. In some embodiments, the heavycut may have a viscosity, measured at 100° C. according to ASTM D445, ofgreater than 10 cSt, such as greater than 20 cSt, greater than 35 cSt,greater than 50 cSt, greater than 75 cSt, or greater than 100 cSt. Invarious embodiments, the mid-cut may have a viscosity intermediate thatof the light and heavy cuts.

Accordingly, in some embodiments, a light cut, including hydrocarbonshaving a boiling point up to about 300° C., for example, may have aviscosity, measured at 40° C., of less than 10 cSt; in otherembodiments, such as when the light cut includes hydrocarbons having aboiling point up to about 250° C., for example, the light cut may have aviscosity, measured at 40° C., of less than 5 cSt; in yet otherembodiments, such as when the light cut includes hydrocarbons having aboiling point up to about 220° C., for example, the light cut may have aviscosity, measured at 40° C., of less than 1 cSt. In some embodimentswhere the light cut includes hydrocarbons having a boiling point belowabout 160° C., the light cut may have a viscosity, measured at 40° C.,of less than 0.75 cSt. While the viscosity may vary for the differentfeeds at any given cut temperature, a low viscosity, such as less than10 cSt, for example, has been found to improve the processability of thelight hydrocarbons in the steam pyrolysis unit without the need forintermediate processing. Light cuts for Arab light crudes processedaccording to embodiments herein may target a viscosity of less than 0.55cSt, for example, and may target a viscosity of less than 0.6 cSt forArab extra light crudes, for example.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a viscosity, measuredat 100° C., of greater than 10 cSt. When the heavy cut includeshydrocarbons having a boiling point above about 350° C., the heavy cutmay have a viscosity, measured at 100° C., of greater than 50 cSt. Whenthe heavy cut includes hydrocarbons having a boiling point above about400° C., the heavy cut may have a viscosity, measured at 100° C., ofgreater than 100 cSt. In embodiments where the heavy cut includeshydrocarbons having a boiling point above about 490° C., the heavy cutmay have a viscosity of greater than 375 cSt, for example. A heavy-cuthaving a viscosity of greater than about 40 cSt, for example, has beenfound to be convertible to steam cracker feeds using the more severedestructive hydrogenation conditions in the heavy-cut conditioningsection of processes herein.

MCRT

In some embodiments, the light cut may have only trace amounts, orundetectable amounts, of microcarbon residue (MCRT). In someembodiments, the mid cut may have a MCRT of less than 5 wt %, such asless than 3 wt %, less than 1 wt %, or less than 0.5 wt %. In someembodiments, the heavy cut may have an MCRT of greater than 0.5 wt %,such as greater than 1 wt %, greater than 3 wt %, greater than 5 wt %,or greater than 10 wt %.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a MCRT of between about 0 wt % (trace or unmeasurable) and 1 wt%. A mid-cut having negligible MCRT, for example, has been found to beconvertible to steam cracker feeds using relatively moderate destructivehydrogenation conditions in the mid-cut conditioning section ofprocesses herein.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a MCRT of greaterthan 0.5 wt %. When the heavy cut includes hydrocarbons having a boilingpoint above about 350° C., the heavy cut may have a MCRT of greater than1 wt %. When the heavy cut includes hydrocarbons having a boiling pointabove about 400° C., the heavy cut may have a MCRT of greater than 5 wt%. In embodiments where the heavy cut includes hydrocarbons having aboiling point above about 490° C., the heavy cut may have a MCRT ofgreater than 15 wt %, for example. A heavy-cut having a MCRT of greaterthan about 1 wt %, for example, has been found to be convertible tosteam cracker feeds using the more severe destructive hydrogenationconditions in the heavy-cut conditioning section of processes herein.

Metals Content

In some embodiments, the light cut may have only trace amounts, orundetectable amounts, of metals. In some embodiments, the mid cut mayhave a metals content of up to 50 ppm, such as less than 30 ppm, lessthan 10 ppm, or less than 1 ppm. In some embodiments, the heavy cut mayhave a metals content of greater than 1 ppm, such as greater than 10ppm, greater than 20 ppm, greater than 35 ppm, or greater than 50 ppm.

In some embodiments, the mid cut, including hydrocarbons having a lowerboiling point in the range from about 90° C. to about 300° C. and anupper boiling point in the range from about 400° C. to about 600° C.,may have a metals content of between about 0 ppm (trace or unmeasurable)and 5 ppm, such as from greater than 0 ppm to 1 ppm. A mid-cut havingnegligible metals content, for example, has been found to be convertibleto steam cracker feeds using relatively moderate destructivehydrogenation conditions in the mid-cut conditioning section ofprocesses herein.

In various embodiments, the heavy cut, including hydrocarbons having aboiling point greater than about 300° C., may have a metals content ofgreater than 1 ppm. When the heavy cut includes hydrocarbons having aboiling point above about 350° C., the heavy cut may have a metalscontent of greater than 10 ppm. When the heavy cut includes hydrocarbonshaving a boiling point above about 400° C., the heavy cut may have ametals content of greater than 50 ppm. In embodiments where the heavycut includes hydrocarbons having a boiling point above about 490° C.,the heavy cut may have a metals content of greater than 75 ppm, forexample. A heavy-cut having a metals content of greater than about 10ppm, for example, has been found to be convertible to steam crackerfeeds using the more severe destructive hydrogenation conditions in theheavy-cut conditioning section of processes herein.

As an example, an Arab Light crude oil stream may be separated in theinitial separation step in order to produce the desired light-, mid-,and heavy-cuts. Without intending to be bound by theory, the light-cutmay be a 160° C.− fraction with 5% of the fraction having a boilingpoint below 36° C. and 95% of the fraction having a boiling point below160° C. (only 5% of the fraction would have a boiling point above 160°C.). The light cut may have an API gravity of about 65.5°, may have aBMCI of about 5.2, may have a hydrogen content of about 14.8 wt % (or148,000 ppm), may have a nitrogen content of less than 0.00003 wt % (or0.3 ppm), may have a sulfur content of about 0.0582 wt % (or 582 ppm),may have a viscosity, at 40° C., of about 0.5353 centistokes (cSt), andmay have only trace amounts of MCRT and total metals content. Themid-cut may be a 160° C. to 490° C. fraction with 5% of the fractionhaving a boiling point below 173° C. and 95% of the fraction having aboiling point below 474° C. (only 5% of the fraction would have aboiling point above 474° C.). The mid-cut may have an API gravity ofabout 33.6°, may have a BMCI of about 25, may have a hydrogen content ofabout 12.83 wt % (or 128,300 ppm), may have a nitrogen content of lessthan 0.0227 wt % (or 227 ppm), may have a sulfur content of about 0.937wt % (or 9,370 ppm), may have a viscosity, at 100° C., of about 1.58centistokes (cSt), may have an MCRT of 0.03 wt %, and may have onlytrace amounts of total metals content. The heavy-cut may be a 490° C.+fraction with 5% of the fraction having a boiling point below 490° C.and 95% of the fraction having a boiling point below 735° C. (only 5% ofthe fraction would have a boiling point above 735° C.). The heavy-cutmay have an API gravity of about 8.2°, may have a BMCI of about 55, mayhave a hydrogen content of about 10.41 wt % (or 104,100 ppm), may have anitrogen content of less than 0.2638 wt % (or 2,368 ppm), may have asulfur content of about 3.9668 wt % (or 39,668 ppm), may have aviscosity, at 100° C., of about 394.3 centistokes (cSt), may have anMCRT of 17.22 wt %, and may have a total metals content 79.04 ppm.

As another example, an Arab Extra Light crude oil stream may beseparated in the initial separation step in order to produce the desiredlight-, mid-, and heavy-cuts. Without intending to be bound by theory,the light-cut may be a 160° C.− fraction with 5% of the fraction havinga boiling point below 54° C. and 95% of the fraction having a boilingpoint below 160° C. (only 5% of the fraction would have a boiling pointabove 160° C.). The light cut may have an API gravity of about 62°, mayhave a BMCI of about 9.09, may have a hydrogen content of about 14.53 wt% (or 145,300 ppm), may have a nitrogen content of less than 0.00003 wt% (or 0.3 ppm), may have a sulfur content of about 0.0472 wt % (or 472ppm), may have a viscosity, at 40° C., of about 0.58 centistokes (cSt),and may have only trace amounts of MCRT and total metals content. Themid-cut may be a 160° C. to 490° C. fraction with 5% of the fractionhaving a boiling point below 169° C. and 95% of the fraction having aboiling point below 456° C. (only 5% of the fraction would have aboiling point above 474° C.). The mid-cut may have an API gravity ofabout 36.1°, may have a BMCI of about 21.22, may have a hydrogen contentof about 13.38 wt % (or 133,800 ppm), may have a nitrogen content ofless than 0.01322 wt % (or 132.2 ppm), may have a sulfur content ofabout 0.9047 wt % (or 9,047 ppm), may have a viscosity, at 100° C., ofabout 1.39 centistokes (cSt), and may have only trace amounts of MCRTand total metals content. The heavy-cut may be a 490° C.+ fraction with5% of the fraction having a boiling point below 455° C. and 95% of thefraction having a boiling point below 735° C. (only 5% of the fractionwould have a boiling point above 735° C.). The heavy-cut may have an APIgravity of about 15.1°, may have a BMCI of about 33.28, may have ahydrogen content of about 11.45 wt % (or 114,500 ppm), may have anitrogen content of less than 0.1599 wt % (or 1,599 ppm), may have asulfur content of about 2.683 wt % (or 26,830 ppm), may have aviscosity, at 100° C., of about 48.79 centistokes (cSt), may have anMCRT of 9.53 wt %, and may have a total metals content 58.45 ppm.

While various properties have been described with respect to Arab Lightand Arab Extra Light, the aforementioned would also be applicable toother types of crude, such as desalted oils, condensate, biogenic oil,synthesis crude, tight oil, heavy hydrocarbons, reconstituted crudes,and bitumen derived oils.

Embodiments herein contemplate adjustment of the various cut points andreactor conditions based upon one or more of the above-noted properties.Methods according to embodiments herein may assay the petroleum feeds tobe used, measuring one or more of the various properties of an incomingfeed. Based on one or more of the properties, cut points, catalyst types(for moving bed reactors), pressures, temperatures, space velocity,hydrogen feed rates, and other variables may be adjusted to moreeffectively and efficiently utilize the reactor configuration, so as tomaintain prime, near optimal, or optimal conditioning of the feedstockand the various cuts to desirable steam cracker feedstocks.

For example, the ebullated bed which receives the heavy-cut may have acapacity to process an amount of hydrocarbon having a sulfur content ofless than 40,000 ppm. If a particular 490° C.+ heavy-cut would have asulfur content of greater than 40,000 ppm, the capacity of the ebullatedbed may be reduced. Accordingly, the heavy-cut point may be reduced, to465° C.+, for example, in order have the sulfur content be less than40,000 ppm. Further, if a particular 160° C.-490° C. mid-cut fractionhas a hydrogen content of greater than 14 wt %, for example, and thenitrogen, sulfur, MCRT, and total metals is suitably low, the light-cutfraction may be expanded (from 160° C.− to 190° C.−, for example) toroute more of the whole crude directly to the steam cracker.Alternatively, if the mid-cut is lower in hydrogen, for example, and/orthe sulfur, nitrogen, MCRT, and/or total metals are not suitably low,the light-cut may be reduced (from 160° C.− to 130° C.−, for example),such that additional mid-cut may be processed in the fixed bedconditioning stages.

Processes herein provide the needed flexibility to maintain a highconversion of various feedstocks to petrochemicals. One skilled in theart, knowing that the types of hydrocarbon components, sulfur content,nitrogen content, etc., may vary widely amongst the various feed types(an Arab extra light crude is much different than a West TexasIntermediate crude), and feeds from various resources may be processedin any given day, week, month, or year, at a given plant, will recognizethe benefits of the processes herein to flexibly produce petrochemicalsfrom many different feedstocks.

As described above, embodiments herein may be used to convert a wholecrude, including the heavier fractions of crude oil, into high-valuepetrochemicals and may minimize the amount sent to a fuel oil pool,which increases profitability. The fuel oil pool may also be upgradedinto a low-sulfur, IMO 2020 compliant fuel oil, further increasing thevalue of the products.

Embodiments herein may initially split the wide boiling rangehydrocarbon feedstock into light, mid, and heavy cuts. The division offeedstocks into the various cuts may allow advantageous processingconditions, reactor sizing, and other factors not achievable in flowschemes that teach one skilled in the art to hydrotreat or otherwisecondition the entirety of a whole crude or even a heavy portion thereof,such as a single 200°+ cut. The ability to prepare steam cracker feedsfrom separate mid cuts and heavy cuts at reaction conditions moresuitable for hydrocarbons in those respective fractions advantageouslyprovides for enhanced production of petrochemicals, as described herein,and provides for one or more of the following advantages: extendedcatalyst life for conditioning the mid-cut; economical reactor sizingfor each of the respective cuts; matched run times of the mid-cutconditioning and the steam cracker; the ability to condition therespective fractions at preferred conditions; the ability to tailor thecatalyst for preferred conditioning of the respective fractions; andother advantages as may readily be envisioned by one skilled in the artbased on the disclosure herein.

As described above, embodiments herein may relate to one or more of thefollowing embodiments:

Embodiment 1

A process for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the process comprising:

-   -   separating a whole crude into at least a light boiling fraction,        a medium boiling fraction, and a high boiling residue fraction;    -   hydrocracking the high boiling residue fraction to form a        hydrocracked effluent, and separating the hydrocracked effluent        to produce a resid hydrocracked fraction and a fuel oil        fraction;    -   destructively hydrogenating and hydrocracking the medium boiling        fraction and the resid hydrocracked fraction to produce a        hydrotreated and hydrocracked effluent;    -   feeding the hydrotreated and hydrocracked effluent and the light        boiling fraction to at least one of a steam cracker and an        aromatics complex to convert hydrocarbons therein into        petrochemicals and a pyrolysis oil and/or an ultra-low sulfur        fuel oil (ULSFO).

Embodiment 2

The process of embodiment 1, wherein the light boiling fraction has twoor more of the following properties:

-   -   a 95% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a hydrogen content of at least 14 wt %;    -   a BMCI of less than 5;    -   an API gravity of greater than 40°;    -   a sulfur content of less than 1000 ppm;    -   a nitrogen content of less than 10 ppm;    -   a viscosity, measured at 40° C., of less than 1 cSt;    -   less than 1 wt % MCRT; and    -   less than 1 ppm total metals.

Embodiment 3

The process of embodiment 1 or embodiment 2, wherein the medium boilingfraction has two or more of the following properties:

-   -   a 5% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a 95% boiling point temperature in the range from about 400° C.        to about 600° C.;    -   a hydrogen content in the range from about 12 wt % to about 14        wt %;    -   a BMCI in the range from about 5 to less than 50;    -   an API gravity of in the range from about 10° to about 40°;    -   a sulfur content in the range from about 1000 ppm to about 10000        ppm;    -   a nitrogen content in the range from about 1 ppm to about 100        ppm;    -   a viscosity, measured at 40° C., of greater than 1 cSt;    -   less than 5 wt % MCRT; and    -   less than 50 ppm total metals.

Embodiment 4

The process of any one of embodiment 1-3, wherein the heavy boilingfraction has two or more of the following properties:

-   -   a 5% boiling point temperature in the range from about 400° C.        to about 600° C.;    -   a hydrogen content of less than 12 wt %;    -   a BMCI of greater than 50;    -   an API gravity of less than 10°;    -   a sulfur content of greater than 10000 ppm;    -   a nitrogen content of greater than 100 ppm;    -   a viscosity, measured at 100° C., of greater than 100 cSt;    -   greater than 5 wt % MCRT; and    -   greater than 50 ppm total metals.

Embodiment 5

The process of any one of embodiments 1-4, wherein:

-   -   the resid hydrocracked fraction has a 95% boiling point        temperature in the range from about 400° C. to about 560° C.

Embodiment 6

The process of any one of embodiments 1-5, wherein the high boilingresidue fraction has a 5% boiling point temperature of greater thanabout 545° C.

Embodiment 7

The process of any one of embodiments 1-6, wherein the hydrocracking thehigh boiling residue fraction comprises contacting the high boilingresidue fraction and the pyrolysis oil with an extrudate or slurrycatalyst at conditions sufficient to convert at least a portion of thehigh boiling residue fraction hydrocarbons to lighter hydrocarbons.

Embodiment 8

The process of any one of embodiments 1-7, wherein hydrocracking thehigh boiling residue fraction comprises converting in excess of 70% ofthe hydrocarbons having a boiling point of greater than 565° C.

Embodiment 9

The process of any one of embodiments 1-8, wherein the destructivelyhydrogenating and hydrocracking the medium boiling fraction and theresid hydrocracked fraction comprises destructive hydrogenation themedium boiling fraction and the resid hydrocracked fraction in a commondestructive hydrogenation unit, and hydrocracking an effluent from thecommon destructive hydrogenation unit in a hydrocracking unit.

Embodiment 10

The process of any one of embodiments 1-9, wherein the destructivelyhydrogenating and hydrocracking the medium boiling fraction and theresid hydrocracked fraction comprises:

-   -   destructively hydrogenating the medium boiling fraction in a        first destructive hydrogenation unit;    -   destructively hydrogenating the resid hydrocracked fraction in a        second destructive hydrogenation unit; and    -   combining the effluents from the first and second destructive        hydrogenation units and hydrocracking the combined effluents in        a hydrocracking unit.

Embodiment 11

The process of embodiment 10, further comprising destructivehydrogenating the resid hydrocracked fraction in the first destructivehydrogenation unit during a time period when catalyst is being replacedin the second destructive hydrogenation unit.

Embodiment 12

The process of any one of embodiments 1-11, further comprisinghydrodesulfurizing the fuel oil fraction to produce an ultra-low sulfurfuel oil.

Embodiment 13

The process of any one of embodiments 1-12, wherein an overallpetrochemicals production is at least 65 wt %, based on a total amountof olefins and aromatics produced as compared to a total feedstock feedrate, inclusive of the whole crude and any additional feeds.

Embodiment 14

The process of any one of embodiments 1-13, wherein feeding thehydrotreated and hydrocracked effluent and the light boiling fraction toat least one of a steam cracker and an aromatics complex comprises:

-   -   separating the hydrotreated and hydrocracked effluent and the        light boiling fraction to a separator to produce a light naphtha        fraction and a heavy naphtha fraction;    -   feeding the light naphtha fraction to the steam cracker unit;        and feeding the heavy naphtha fraction to the aromatics complex.

Embodiment 15

The process of any one of embodiments 1-14, comprising feeding thehydrotreated and hydrocracked effluent and the light boiling fractiondirectly to the steam cracker.

Embodiment 16

A process for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the process comprising:

-   -   separating a whole crude into at least a light boiling fraction,        a medium boiling fraction, and a high boiling residue fraction;    -   hydrocracking the high boiling residue fraction to form a        hydrocracked effluent, and separating the hydrocracked effluent        to produce a resid hydrocracked fraction and a fuel oil        fraction;    -   destructively hydrogenating the medium boiling fraction to form        a first destructively hydrogenated effluent;    -   destructively hydrogenating the resid hydrocracked fraction to        produce a second destructively hydrogenated effluent    -   mixing the first and second destructively hydrogenated effluents        to form a mixture and hydrocracking the mixture to produce a        hydrotreated and hydrocracked effluent;    -   feeding the hydrotreated and hydrocracked effluent and the light        boiling fraction to at least one of a steam cracker and an        aromatics complex to convert hydrocarbons therein into        petrochemicals and a pyrolysis oil and/or an ultra-low sulfur        fuel oil (ULSFO).

Embodiment 17

A process for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the process comprising:

-   -   separating a whole crude into at least a light boiling fraction,        a medium boiling fraction, and a high boiling residue fraction;    -   hydrocracking the high boiling residue fraction to form a        hydrocracked effluent, and separating the hydrocracked effluent        to produce a resid hydrocracked fraction and a fuel oil        fraction;    -   destructively hydrogenating the medium boiling fraction to form        a first destructively hydrogenated effluent;    -   destructively hydrogenating the resid hydrocracked fraction to        produce a second destructively hydrogenated effluent    -   mixing the first and second destructively hydrogenated effluents        to form a mixture and hydrocracking the mixture to form produce        a hydrotreated and hydrocracked effluent;    -   feeding the hydrotreated and hydrocracked effluent and the light        boiling fraction to at least one of a steam cracker and an        aromatics complex to convert hydrocarbons therein into        petrochemicals and a pyrolysis oil and/or an ultra-low sulfur        fuel oil (ULSFO).

Embodiment 18

The process of embodiment 17, wherein the light boiling fraction has twoor more of the following properties:

-   -   a 95% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a hydrogen content of at least 14 wt %;    -   a BMCI of less than 5;    -   an API gravity of greater than 40°;    -   a sulfur content of less than 1000 ppm;    -   a nitrogen content of less than 10 ppm;    -   a viscosity, measured at 40° C., of less than 1 cSt;    -   less than 1 wt % MCRT; and    -   less than 1 ppm total metals.

Embodiment 19

The process of embodiment 17 or embodiment 18, wherein the mediumboiling fraction has two or more of the following properties:

-   -   a 5% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a 95% boiling point temperature in the range from about 400° C.        to about 600° C.;    -   a hydrogen content in the range from about 12 wt % to about 14        wt %;    -   a BMCI in the range from about 5 to less than 50;    -   an API gravity of in the range from about 10° to about 40°;    -   a sulfur content in the range from about 1000 ppm to about 10000        ppm;    -   a nitrogen content in the range from about 1 ppm to about 100        ppm;    -   a viscosity, measured at 40° C., of greater than 1 cSt;    -   less than 5 wt % MCRT; and    -   less than 50 ppm total metals.

Embodiment 20

The process of any one of embodiment 17-19, wherein the heavy boilingfraction has two or more of the following properties:

-   -   a 5% boiling point temperature in the range from about 400° C.        to about 600° C.;    -   a hydrogen content of less than 12 wt %;    -   a BMCI of greater than 50;    -   an API gravity of less than 10°;    -   a sulfur content of greater than 10000 ppm;    -   a nitrogen content of greater than 100 ppm;    -   a viscosity, measured at 100° C., of greater than 100 cSt;    -   greater than 5 wt % MCRT; and    -   greater than 50 ppm total metals.

Embodiment 21

The process of any one of embodiments 17-20, wherein:

-   -   the resid hydrocracked fraction has a 95% boiling point        temperature in the range from about 400° C. to about 560° C.

Embodiment 22

The process of any one of embodiments 17-21, wherein the high boilingresidue fraction has a 5% boiling point temperature of greater thanabout 545° C.

Embodiment 23

The process of any one of embodiments 17-22, wherein the hydrocrackingthe high boiling residue fraction comprises contacting the high boilingresidue fraction and the pyrolysis oil with an extrudate or slurrycatalyst at conditions sufficient to convert at least a portion of thehigh boiling residue fraction hydrocarbons to lighter hydrocarbons.

Embodiment 24

The process of any one of embodiments 17-23, wherein hydrocracking thehigh boiling residue fraction comprises converting in excess of 70% ofthe hydrocarbons having a boiling point of greater than 565° C.

Embodiment 25

The process of any one of embodiments 17-24, wherein the destructivelyhydrogenating the medium boiling fraction and the destructivelyhydrogenating the resid hydrocracked fraction comprises destructivehydrogenating the medium boiling fraction and the resid hydrocrackedfraction in a common destructive hydrogenation unit.

Embodiment 26

The process of any one of embodiments 17-25, wherein the destructivelyhydrogenating the medium boiling fraction and the destructivelyhydrogenating the resid hydrocracked fraction comprises:

-   -   destructively hydrogenating the medium boiling fraction in a        first destructive hydrogenation unit;    -   destructively hydrogenating the resid hydrocracked fraction in a        second destructive hydrogenation unit; and    -   combining the effluents from the first and second destructive        hydrogenation units.

Embodiment 27

The process of embodiment 26, further comprising destructivehydrogenating the resid hydrocracked fraction in the first destructivehydrogenation unit during a time period when catalyst is being replacedin the second destructive hydrogenation unit.

Embodiment 28

The process of any one of embodiments 17-27, further comprisinghydrodesulfurizing the fuel oil fraction to produce an ultra-low sulfurfuel oil.

Embodiment 29

The process of any one of embodiments 17-28, wherein an overallpetrochemicals production is at least 65 wt %, based on a total amountof olefins and aromatics produced as compared to a total feedstock feedrate, inclusive of the whole crude and any additional feeds.

Embodiment 30

The process of any one of embodiments 17-29, wherein feeding thehydrotreated and hydrocracked effluent and the light boiling fraction toat least one of a steam cracker and an aromatics complex comprises:

-   -   separating the hydrotreated and hydrocracked effluent and the        light boiling fraction to a separator to produce a light naphtha        fraction and a heavy naphtha fraction;    -   feeding the light naphtha fraction to the steam cracker unit;        and feeding the heavy naphtha fraction to the aromatics complex.

Embodiment 31

The process of any one of embodiments 17-30, comprising feeding thehydrotreated and hydrocracked effluent and the light boiling fractiondirectly to the steam cracker.

Embodiment 32

A process for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the process comprising:

-   -   separating a whole crude into at least a first fraction, a        second fraction, and a third fraction, wherein:        -   the first fraction has a BMCI of less than 20 and a hydrogen            content of greater than 13 wt %;        -   the third fraction has a BMCI of greater than 30 and a            hydrogen content of less than 13 wt %;        -   and the second fraction has a BMCI and a hydrogen content            intermediate the respective values for the first and third            fractions;    -   hydrocracking the third fraction to form a hydrocracked        effluent, and separating the hydrocracked effluent to produce a        resid hydrocracked fraction and a fuel oil fraction;    -   destructively hydrogenating and hydrocracking the second        fraction and the resid hydrocracked fraction to produce a        hydrotreated and hydrocracked effluent;    -   feeding the hydrotreated and hydrocracked effluent and the first        fraction to at least one of a steam cracker and an aromatics        complex to convert hydrocarbons therein into petrochemicals and        a pyrolysis oil and/or an ultra-low sulfur fuel oil (ULSFO).

Embodiment 33

A process for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the process comprising:

-   -   separating a whole crude into at least a light boiling fraction,        a medium boiling fraction, and a high boiling residue fraction;    -   hydrocracking the high boiling residue fraction and a heavy        fraction to form a hydrocracked effluent, and separating the        hydrocracked effluent to produce a resid hydrocracked fraction        and a fuel oil fraction;    -   destructively hydrogenating and hydrocracking the medium boiling        fraction and the resid hydrocracked fraction to produce a        hydrotreated and hydrocracked effluent;    -   separating the hydrotreated and hydrocracked effluent to produce        a light fraction and the heavy fraction;    -   feeding the light fraction and the light boiling fraction to a        separator to recover a light naphtha fraction and a heavy        naphtha fraction;    -   feeding the light naphtha fraction to a steam cracker to convert        the light naphtha fraction into petrochemicals including        ethylene, propylene, and butenes; and    -   feeding the heavy naphtha fraction to an aromatics complex to        convert hydrocarbons therein into petrochemicals including        benzene, toluene, and xylenes.

Embodiment 34

The process of embodiment 33, further comprising mixing a slurry oilwith the high boiling residue fraction prior to hydrocracking the highboiling residue fraction.

Embodiment 35

The process of embodiment 33 or 34, further comprising mixing a lightcycle oil with the medium boiling fraction prior to the destructivelyhydrogenating and hydrocracking the medium boiling fraction.

Embodiment 36

A process for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the process comprising:

-   -   separating a whole crude in a first separation device into a        light boiling fraction and a remainder fraction;    -   separating the reminder fraction in a second separation device        into a medium boiling fraction and a high boiling residue        fraction;    -   hydrocracking the high boiling residue fraction to form a        hydrocracked effluent;    -   separating the hydrocracked effluent to produce a first        converted fraction and a first heavy fraction;    -   hydrocracking the first heavy fraction to form a second        hydrocracked effluent;    -   separating the second hydrocracked effluent to produce a resid        hydrocracked fraction and a fuel oil fraction;    -   destructively hydrogenating the medium boiling fraction, the        first converted fraction, and the resid hydrocracked fraction to        produce a hydrotreated effluent;    -   separating the hydrotreated effluent to produce a lights        fraction comprising hydrogen and hydrogen sulfide, a sour water        stream, and a hydrotreated fraction;    -   hydrocracking the hydrotreated fraction and a pyrolysis oil        fraction to produce a second hydrocracked effluent;    -   separating the second hydrocracked effluent to recover a lights        fraction comprising hydrogen and a hydrocracked fraction;    -   feeding the light fraction and the hydrocracked fraction to a        separator to recover a light naphtha fraction and a heavy        naphtha fraction;    -   feeding the light naphtha fraction to a steam cracker to convert        the light naphtha fraction into petrochemicals including        ethylene, propylene, and butenes; and    -   feeding the heavy naphtha fraction to an aromatics complex to        convert hydrocarbons therein into petrochemicals including        benzene, toluene, and xylenes.

Embodiment 37

The embodiments of any one of embodiments 1-36, wherein the lightboiling fraction or the first fraction, appropriately, has two or moreof the following properties:

-   -   a 95% boiling point temperature in the range from about 90° C.        to about 300° C.;    -   a hydrogen content of at least 13 wt %;    -   a BMCI of less than 20;    -   an API gravity of greater than 10°;    -   a sulfur content of less than 1 wt %;    -   a nitrogen content of less than 100 ppm;    -   a viscosity, measured at 40° C., of less than 10 cSt;    -   less than 1 wt % MCRT; and    -   less than 1 ppm total metals.

Embodiment 38

The embodiments of any one of embodiments 1-36, wherein the lightboiling fraction or the first fraction, appropriately, has two or moreof the following properties:

-   -   a 95% boiling point temperature in the range from about 110° C.        to about 250° C.;    -   a hydrogen content of at least 13.5 wt %;    -   a BMCI of less than 10;    -   an API gravity of greater than 20°;    -   a sulfur content of less than 5000 ppm;    -   a nitrogen content of less than 10 ppm;    -   a viscosity, measured at 40° C., of less than 5 cSt;    -   less than 1 wt % MCRT; and    -   less than 1 ppm total metals.

Embodiment 39

The embodiments of any one of embodiments 1-36, wherein the lightboiling fraction or the first fraction, appropriately, has two or moreof the following properties:

-   -   a 95% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a hydrogen content of at least 14 wt %;    -   a BMCI of less than 5;    -   an API gravity of greater than 40°;    -   a sulfur content of less than 1000 ppm;    -   a nitrogen content of less than 1 ppm;    -   a viscosity, measured at 40° C., of less than 1 cSt;    -   less than 1 wt % MCRT; and    -   less than 1 ppm total metals.

Embodiment 40

The embodiments of any one of embodiments 1-36, wherein the mediumboiling fraction or the second fraction, appropriately, has two or moreof the following properties:

-   -   a 5% boiling point temperature in the range from about 130° C.        to about 200° C.;    -   a 95% boiling point temperature in the range from about 400° C.        to about 600° C.;    -   a hydrogen content in the range from about 12 wt % to about 14        wt %;    -   a BMCI in the range from about 5 to less than 50;    -   an API gravity of in the range from about 10° to about 40°;    -   a sulfur content in the range from about 1000 ppm to about 10000        ppm;    -   a nitrogen content in the range from about 1 ppm to about 100        ppm;    -   a viscosity, measured at 40° C., of greater than 1 cSt;    -   less than 5 wt % MCRT; and    -   less than 50 ppm total metals.

Embodiment 41

The embodiments of any one of embodiments 1-36, wherein the mediumboiling fraction or the second fraction, appropriately, has two or moreof the following properties:

-   -   a 5% boiling point temperature in the range from about 110° C.        to about 250° C.;    -   a 95% boiling point temperature in the range from about 350° C.        to about 650° C.;    -   a hydrogen content in the range from about 12 wt % to about 14        wt %;    -   a BMCI in the range from about 5 to less than 50;    -   an API gravity of in the range from about 10° to about 40°;    -   a sulfur content in the range from about 1000 ppm to about 10000        ppm;    -   a nitrogen content in the range from about 1 ppm to about 100        ppm;    -   a viscosity, measured at 40° C., of greater than 1 cSt;    -   less than 5 wt % MCRT; and    -   less than 50 ppm total metals.

Embodiment 42

The embodiments of any one of embodiments 1-36, wherein the mediumboiling fraction or the second fraction, appropriately, has two or moreof the following properties:

-   -   a 5% boiling point temperature in the range from about 90° C. to        about 300° C.;    -   a 95% boiling point temperature in the range from about 300° C.        to about 700° C.;    -   a hydrogen content in the range from about 12 wt % to about 14        wt %;    -   a BMCI in the range from about 5 to less than 50;    -   an API gravity of in the range from about 10° to about 40°;    -   a sulfur content in the range from about 1000 ppm to about 10000        ppm;    -   a nitrogen content in the range from about 1 ppm to about 100        ppm;    -   a viscosity, measured at 40° C., of greater than 1 cSt;    -   less than 5 wt % MCRT; and    -   less than 50 ppm total metals.

Embodiment 43

The embodiments of any one of embodiments 1-36, wherein the heavyboiling fraction or the third fraction, appropriately, has two or moreof the following properties:

-   -   a 5% boiling point temperature in the range from about 300° C.        to about 700° C.;    -   a hydrogen content of less than 13 wt %;    -   a BMCI of greater than 30;    -   an API gravity of less than 40°;    -   a sulfur content of greater than 1000 ppm;    -   a nitrogen content of greater than 10 ppm;    -   a viscosity, measured at 100° C., of greater than 10 cSt;    -   greater than 0.5 wt % MCRT; and    -   greater than 1 ppm total metals.

Embodiment 44

The embodiments of any one of embodiments 1-36, wherein the heavyboiling fraction or the third fraction, appropriately, has two or moreof the following properties:

-   -   a 5% boiling point temperature in the range from about 350° C.        to about 650° C.;    -   a hydrogen content of less than 12.5 wt %;    -   a BMCI of greater than 40;    -   an API gravity of less than 20°;    -   a sulfur content of greater than 5000 ppm;    -   a nitrogen content of greater than 50 ppm;    -   a viscosity, measured at 100° C., of greater than 50 cSt;    -   greater than 1 wt % MCRT; and    -   greater than 10 ppm total metals.

Embodiment 45

The embodiments of any one of embodiments 1-36, wherein the heavyboiling fraction or the third fraction, appropriately, has two or moreof the following properties:

-   -   a 5% boiling point temperature in the range from about 400° C.        to about 600° C.;    -   a hydrogen content of less than 12 wt %;    -   a BMCI of greater than 50;    -   an API gravity of less than 10°;    -   a sulfur content of greater than 10000 ppm;    -   a nitrogen content of greater than 100 ppm;    -   a viscosity, measured at 100° C., of greater than 100 cSt;    -   greater than 5 wt % MCRT; and    -   greater than 50 ppm total metals.

Embodiment 46

A system for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the system comprising:

-   -   a separation system for separating a whole crude into at least a        light boiling fraction, a medium boiling fraction, and a high        boiling residue fraction;    -   a hydrocracking reaction zone for hydrocracking the high boiling        residue fraction to form a hydrocracked effluent, and a        separation system for separating the hydrocracked effluent to        produce a resid hydrocracked fraction and a fuel oil fraction;    -   a reaction zone for destructively hydrogenating and        hydrocracking the medium boiling fraction and the resid        hydrocracked fraction to produce a hydrotreated and hydrocracked        effluent;    -   a steam cracker and optionally an aromatics complex for        converting the hydrotreated and hydrocracked effluent and the        light boiling fraction into petrochemicals and a pyrolysis oil        and/or an ultra-low sulfur fuel oil (ULSFO).

Embodiment 47

The system of embodiment 46, wherein the hydrocracking reaction zone forhydrocracking the high boiling residue fraction comprises a slurryreactor or an ebullated bed reactor.

Embodiment 48

The system of any one of embodiments 46-47, wherein the reaction zonefor destructively hydrogenating and hydrocracking the medium boilingfraction and the resid hydrocracked fraction comprises a commondestructive hydrogenation unit for destructively hydrogenating themedium boiling fraction and the resid hydrocracked fraction, and ahydrocracking reactor for hydrocracking an effluent from the commondestructive hydrogenation unit.

Embodiment 49

The system of any one of embodiments 46-48, wherein the reaction zonefor destructively hydrogenating and hydrocracking the medium boilingfraction and the resid hydrocracked fraction comprises:

-   -   a first destructive hydrogenation unit for destructively        hydrogenating the medium boiling fraction;    -   a second destructive hydrogenation unit for destructively        hydrogenating the resid hydrocracked fraction; and    -   a mixer for combining the effluents from the first and second        destructive hydrogenation units.

Embodiment 50

The system of embodiment 49, further comprising a flow diverter fordiverting the resid hydrocracked fraction to the first destructivehydrogenation unit during a time period when catalyst is being replacedin the second destructive hydrogenation unit.

Embodiment 51

The system of any one of embodiments 46-50, further comprising a reactorfor hydrodesulfurizing the fuel oil fraction to produce an ultra-lowsulfur fuel oil.

Embodiment 52

The system of any one of embodiments 46-51, further comprising:

-   -   a separator for separating the hydrotreated and hydrocracked        effluent and the light boiling fraction to produce a light        naphtha fraction and a heavy naphtha fraction;    -   a flow line for feeding the light naphtha fraction to the steam        cracker unit; and    -   a flow line for feeding the heavy naphtha fraction to the        aromatics complex.

Embodiment 53

A system for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the process comprising:

-   -   a separation system for separating a whole crude into at least a        light boiling fraction, a medium boiling fraction, and a high        boiling residue fraction;    -   a hydrocracker for hydrocracking the high boiling residue        fraction to form a hydrocracked effluent, and a separator for        separating the hydrocracked effluent to produce a resid        hydrocracked fraction and a fuel oil fraction;    -   a first conditioning unit for destructively hydrogenating the        medium boiling fraction to form a first destructively        hydrogenated effluent;    -   a second conditioning unit for destructively hydrogenating the        resid hydrocracked fraction to produce a second destructively        hydrogenated effluent;    -   a mixer for mixing the first and second destructively        hydrogenated effluents to form a mixture and a hydrocracker for        hydrocracking the mixture to produce a hydrotreated and        hydrocracked effluent;    -   a flow line for feeding the hydrotreated and hydrocracked        effluent and the light boiling fraction to at least one of a        steam cracker and an aromatics complex to convert hydrocarbons        therein into petrochemicals and a pyrolysis oil and/or an        ultra-low sulfur fuel oil (ULSFO).

Embodiment 54

A system for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the system comprising:

-   -   a separation system for separating a whole crude into at least a        light boiling fraction, a medium boiling fraction, and a high        boiling residue fraction;    -   a hydrocracker for hydrocracking the high boiling residue        fraction to form a hydrocracked effluent, and separating the        hydrocracked effluent to produce a resid hydrocracked fraction        and a fuel oil fraction;    -   a first conditioning reactor for destructively hydrogenating the        medium boiling fraction to form a first destructively        hydrogenated effluent;    -   a second conditioning reactor for destructively hydrogenating        the resid hydrocracked fraction to produce a second        destructively hydrogenated effluent;    -   a mixer for mixing the first and second destructively        hydrogenated effluents to form a mixture and a hydrocracker for        hydrocracking the mixture to form produce a hydrotreated and        hydrocracked effluent;    -   one or more flow lines for feeding the hydrotreated and        hydrocracked effluent and the light boiling fraction to at least        one of a steam cracker and an aromatics complex to convert        hydrocarbons therein into petrochemicals and a pyrolysis oil        and/or an ultra-low sulfur fuel oil (ULSFO).

Embodiment 55

The system of embodiment 54, wherein the hydrocracker for hydrocrackingthe high boiling residue fraction comprises a slurry reactor or anebullated bed reactor.

Embodiment 56

The system of embodiment 55, further comprising a flow line fordiverting the resid hydrocracked fraction to the first destructivehydrogenation unit during a time period when catalyst is being replacedin the second destructive hydrogenation unit.

Embodiment 57

The system of any one of embodiments 54-56, further comprising a reactorfor hydrodesulfurizing the fuel oil fraction to produce an ultra-lowsulfur fuel oil.

Embodiment 58

The system of any one of embodiments 54-57, comprising:

-   -   a separator for separating the hydrotreated and hydrocracked        effluent and the light boiling fraction to produce a light        naphtha fraction and a heavy naphtha fraction;    -   a flow line for feeding the light naphtha fraction to the steam        cracker unit; and    -   a flow line for feeding the heavy naphtha fraction to the        aromatics complex.

Embodiment 59

A system for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the system comprising:

-   -   a separation system for separating a whole crude into at least a        first fraction, a second fraction, and a third fraction,        wherein:        -   the first fraction has a BMCI of less than 20 and a hydrogen            content of greater than 13 wt %;        -   the third fraction has a BMCI of greater than 30 and a            hydrogen content of less than 13 wt %;        -   and the second fraction has a BMCI and a hydrogen content            intermediate the respective values for the first and third            fractions;    -   a hydrocracker for hydrocracking the third fraction to form a        hydrocracked effluent, and a separator for separating the        hydrocracked effluent to produce a resid hydrocracked fraction        and a fuel oil fraction;    -   a conditioning zone for destructively hydrogenating and        hydrocracking the second fraction and the resid hydrocracked        fraction to produce a hydrotreated and hydrocracked effluent;    -   one or more flow lines for feeding the hydrotreated and        hydrocracked effluent and the first fraction to at least one of        a steam cracker and an aromatics complex to convert hydrocarbons        therein into petrochemicals and a pyrolysis oil and/or an        ultra-low sulfur fuel oil (ULSFO).

Embodiment 60

A system for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the system comprising:

-   -   a separation system for separating a whole crude into at least a        light boiling fraction, a medium boiling fraction, and a high        boiling residue fraction;    -   a hydrocracker for hydrocracking the high boiling residue        fraction and a heavy fraction to form a hydrocracked effluent,        and a separator for separating the hydrocracked effluent to        produce a resid hydrocracked fraction and a fuel oil fraction;    -   a conditioning zone for destructively hydrogenating and        hydrocracking the medium boiling fraction and the resid        hydrocracked fraction to produce a hydrotreated and hydrocracked        effluent;    -   a separator for separating the hydrotreated and hydrocracked        effluent to produce a light fraction and the heavy fraction;    -   a separator for separating the light fraction and the light        boiling fraction to recover a light naphtha fraction and a heavy        naphtha fraction;    -   a steam cracker for converting the light naphtha fraction        fraction into petrochemicals including ethylene, propylene, and        butenes; and an aromatics complex for converting the heavy        naphtha into petrochemicals including benzene, toluene, and        xylenes.

Embodiment 61

The system of embodiment 60, further comprising a mixer for mixing aslurry oil with the high boiling residue fraction upstream of thehydrocracker for hydrocracking the high boiling residue fraction.

Embodiment 62

The system of embodiment 60 or 61, further comprising a mixer for mixinga light cycle oil with the medium boiling fraction.

Embodiment 63

A system for converting whole crudes and other wide boiling hydrocarbonstreams to produce olefins and/or aromatics, the system comprising:

-   -   a separation system for separating a whole crude in a first        separation device into a light boiling fraction and a remainder        fraction;    -   a separation system for separating the reminder fraction in a        second separation device into a medium boiling fraction and a        high boiling residue fraction;    -   a hydrocracker for hydrocracking the high boiling residue        fraction to form a hydrocracked effluent;    -   a separator for separating the hydrocracked effluent to produce        a first converted fraction and a first heavy fraction;    -   a hydrocracker for hydrocracking the first heavy fraction to        form a second hydrocracked effluent;    -   a separator for separating the second hydrocracked effluent to        produce a resid hydrocracked fraction and a fuel oil fraction;    -   a conditioning reactor for destructively hydrogenating the        medium boiling fraction, the first converted fraction, and the        resid hydrocracked fraction to produce a hydrotreated effluent;    -   a separator for separating the hydrotreated effluent to produce        a lights fraction comprising hydrogen and hydrogen sulfide, a        sour water stream, and a hydrotreated fraction;    -   a hydrocracker for hydrocracking the hydrotreated fraction and a        pyrolysis oil fraction to produce a second hydrocracked        effluent;    -   a separator for separating the second hydrocracked effluent to        recover a lights fraction comprising hydrogen and a hydrocracked        fraction;    -   a separator for separator the light fraction and the        hydrocracked fraction to recover a light naphtha fraction and a        heavy naphtha fraction;    -   a steam cracker for converting the light naphtha fraction into        petrochemicals including ethylene, propylene, and butenes; and    -   an aromatics complex for converting the heavy naphtha fraction        into petrochemicals including benzene, toluene, and xylenes.

Embodiment 64

The system of any one of embodiments 46-63, wherein the separationsystem for separating the whole crude comprises:

-   -   a heater for heating the whole crude to produce a heated whole        crude;    -   a separator for separating the heated whole crude to recover a        first fraction and a remainder fraction;    -   a heater for heating the remainder fraction to produce a heated        remainder fraction;    -   a hot hydrogen stripper for separating the heated remainder        fraction to produce an overheads comprising hydrogen and a        second fraction and a bottoms comprising a third fraction.

Embodiment 65

The system of embodiment 64, further comprising a heat exchanger forexchanging heat between the remainder fraction and the bottoms.

While the disclosure includes a limited number of embodiments, thoseskilled in the art, having benefit of this disclosure, will appreciatethat other embodiments may be devised which do not depart from the scopeof the present disclosure.

We claim:
 1. A process for converting whole crudes and other wideboiling hydrocarbon streams to produce olefins and/or aromatics, theprocess comprising: separating a whole crude into at least a lightboiling fraction, a medium boiling fraction, and a high boiling residuefraction; hydrocracking the high boiling residue fraction to form ahydrocracked effluent, and separating the hydrocracked effluent toproduce a resid hydrocracked fraction and a fuel oil fraction;destructively hydrogenating the medium boiling fraction to form a firstdestructively hydrogenated effluent; destructively hydrogenating theresid hydrocracked fraction to produce a second destructivelyhydrogenated effluent mixing the first and second destructivelyhydrogenated effluents to form a mixture and hydrocracking the mixtureto form produce a hydrotreated and hydrocracked effluent; feeding thehydrotreated and hydrocracked effluent and the light boiling fraction toat least one of a steam cracker and an aromatics complex to converthydrocarbons therein into petrochemicals and a pyrolysis oil and/or anultra-low sulfur fuel oil (ULSFO).
 2. The process of claim 1, whereinthe light boiling fraction has two or more of the following properties:a 95% boiling point temperature in the range from about 130° C. to about200° C.; a hydrogen content of at least 14 wt %; a BMCI of less than 5;an API gravity of greater than 40°; a sulfur content of less than 1000ppm; a nitrogen content of less than 10 ppm; a viscosity, measured at40° C., of less than 1 cSt; less than 1 wt % MCRT; and less than 1 ppmtotal metals.
 3. The process of claim 1, wherein the medium boilingfraction has two or more of the following properties: a 5% boiling pointtemperature in the range from about 130° C. to about 200° C.; a 95%boiling point temperature in the range from about 400° C. to about 600°C.; a hydrogen content in the range from about 12 wt % to about 14 wt %;a BMCI in the range from about 5 to less than 50; an API gravity of inthe range from about 10° to about 40°; a sulfur content in the rangefrom about 1000 ppm to about 10000 ppm; a nitrogen content in the rangefrom about 1 ppm to about 100 ppm; a viscosity, measured at 40° C., ofgreater than 1 cSt; less than 5 wt % MCRT; and less than 50 ppm totalmetals.
 4. The process of claim 1, wherein the heavy boiling fractionhas two or more of the following properties: a 5% boiling pointtemperature in the range from about 400° C. to about 600° C.; a hydrogencontent of less than 12 wt %; a BMCI of greater than 50; an API gravityof less than 10°; a sulfur content of greater than 10000 ppm; a nitrogencontent of greater than 100 ppm; a viscosity, measured at 100° C., ofgreater than 100 cSt; greater than 5 wt % MCRT; and greater than 50 ppmtotal metals.
 5. The process of claim 1, wherein: the resid hydrocrackedfraction has a 95% boiling point temperature in the range from about400° C. to about 560° C.
 6. The process of claim 1, wherein the highboiling residue fraction has a 5% boiling point temperature of greaterthan about 545° C.
 7. The process of claim 1, wherein the hydrocrackingthe high boiling residue fraction comprises contacting the high boilingresidue fraction and the pyrolysis oil with an extrudate or slurrycatalyst at conditions sufficient to convert at least a portion of thehigh boiling residue fraction hydrocarbons to lighter hydrocarbons. 8.The process of claim 1, wherein hydrocracking the high boiling residuefraction comprises converting in excess of 70% of the hydrocarbonshaving a boiling point of greater than 565° C.
 9. The process of claim1, wherein the destructively hydrogenating the medium boiling fractionand the destructively hydrogenating the resid hydrocracked fractioncomprises destructive hydrogenating the medium boiling fraction and theresid hydrocracked fraction in a common destructive hydrogenation unit.10. The process of claim 1, wherein the destructively hydrogenating themedium boiling fraction and the destructively hydrogenating the residhydrocracked fraction comprises: destructively hydrogenating the mediumboiling fraction in a first destructive hydrogenation unit;destructively hydrogenating the resid hydrocracked fraction in a seconddestructive hydrogenation unit; and combining the effluents from thefirst and second destructive hydrogenation units.
 11. The process ofclaim 10, further comprising destructive hydrogenating the residhydrocracked fraction in the first destructive hydrogenation unit duringa time period when catalyst is being replaced in the second destructivehydrogenation unit.
 12. The process of claim 1, further comprisinghydrodesulfurizing the fuel oil fraction to produce an ultra-low sulfurfuel oil.
 13. The process of claim 1, wherein an overall petrochemicalsproduction is at least 65 wt %, based on a total amount of olefins andaromatics produced as compared to a total feedstock feed rate, inclusiveof the whole crude and any additional feeds.
 14. The process of claim 1,wherein feeding the hydrotreated and hydrocracked effluent and the lightboiling fraction to at least one of a steam cracker and an aromaticscomplex comprises: separating the hydrotreated and hydrocracked effluentand the light boiling fraction to a separator to produce a light naphthafraction and a heavy naphtha fraction; feeding the light naphthafraction to the steam cracker unit; and feeding the heavy naphthafraction to the aromatics complex.
 15. The process of claim 1,comprising feeding the hydrotreated and hydrocracked effluent and thelight boiling fraction directly to the steam cracker.
 16. The process ofclaim 1, wherein the whole crude is a condensate, and wherein the lightboiling fraction has a 95% boiling point temperature in the range fromabout 500° C. to about 565° C.
 17. A system for converting whole crudesand other wide boiling hydrocarbon streams to produce olefins and/oraromatics, the system comprising: a separation system for separating awhole crude into at least a light boiling fraction, a medium boilingfraction, and a high boiling residue fraction; a hydrocracker forhydrocracking the high boiling residue fraction to form a hydrocrackedeffluent, and separating the hydrocracked effluent to produce a residhydrocracked fraction and a fuel oil fraction; a first conditioningreactor for destructively hydrogenating the medium boiling fraction toform a first destructively hydrogenated effluent; a second conditioningreactor for destructively hydrogenating the resid hydrocracked fractionto produce a second destructively hydrogenated effluent; a mixer formixing the first and second destructively hydrogenated effluents to forma mixture and a hydrocracker for hydrocracking the mixture to formproduce a hydrotreated and hydrocracked effluent; one or more flow linesfor feeding the hydrotreated and hydrocracked effluent and the lightboiling fraction to at least one of a steam cracker and an aromaticscomplex to convert hydrocarbons therein into petrochemicals and apyrolysis oil and/or an ultra-low sulfur fuel oil (ULSFO).
 18. Thesystem of claim 17, wherein the hydrocracker for hydrocracking the highboiling residue fraction comprises a slurry reactor or an ebullated bedreactor.
 19. The system of claim 18, further comprising a flow line fordiverting the resid hydrocracked fraction to the first destructivehydrogenation unit during a time period when catalyst is being replacedin the second destructive hydrogenation unit.
 20. The system of claim17, further comprising a reactor for hydrodesulfurizing the fuel oilfraction to produce an ultra-low sulfur fuel oil.
 21. The system ofclaim 17, comprising: a separator for separating the hydrotreated andhydrocracked effluent and the light boiling fraction to produce a lightnaphtha fraction and a heavy naphtha fraction; a flow line for feedingthe light naphtha fraction to the steam cracker unit; and a flow linefor feeding the heavy naphtha fraction to the aromatics complex.
 22. Thesystem of claim 17, wherein the separation system for separating thewhole crude comprises: a heater for heating the whole crude to produce aheated whole crude; a separator for separating the heated whole crude torecover a first fraction and a remainder fraction; a heater for heatingthe remainder fraction to produce a heated remainder fraction; a hothydrogen stripper for separating the heated remainder fraction toproduce an overheads comprising hydrogen and a second fraction and abottoms comprising a third fraction.
 23. The system of claim 22, furthercomprising a heat exchanger for exchanging heat between the remainderfraction and the bottoms.